8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

November 1, 2012

Date of Report (Date of earliest event reported)

Commission File Number	Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number
1-16169	EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398	23-2990190
333-85496	EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959	23-3064219
1-1839	COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321	36-0938600
000-16844	PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000	23-0970240
1-1910	BALTIMORE GAS AND ELECTRIC COMPANY (a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201 (410) 234-5000	52-0280210

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Section 2 – Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 – Regulation FD

Item 7.01. Regulation FD Disclosure.

On November 1, 2012, Exelon Corporation (Exelon) announced via press release its results for the third quarter ended September 30, 2012. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the third quarter 2012 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 10:00 AM ET (9:00 AM CT) on November 1, 2012. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 33703408. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

Telephone replays will be available until November 15, 2012. The U.S. and Canada call-in number for replays is 800-585-8367, and the international call-in number is 404-537-3406. The conference ID number is 33703408.

Section 9 – Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

Exhibit No.	Description
99.1	Press release and earnings release attachments
99.2	Earnings conference call presentation slides

* * * * *

This combined Form 8-K is being furnished separately by Exelon, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, and Baltimore Gas and Electric Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

This Current Report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as those discussed in (1) Exelon’s 2011 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Constellation Energy Group’s 2011 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 12; (3) the Registrant’s Second Quarter 2012 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 16; and (4) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Current Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Current Report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

EXELON CORPORATION

/s/ Jonathan W. Thayer

Jonathan W. Thayer

Executive Vice President and Chief Financial Officer

Exelon Corporation

EXELON GENERATION COMPANY, LLC

/s/ Andrew L. Good

Andrew L. Good

Senior Vice President and Chief Financial Officer Exelon Generation Company, LLC

COMMONWEALTH EDISON COMPANY

/s/ Joseph R. Trpik, Jr.

Joseph R. Trpik, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

Commonwealth Edison Company

PECO ENERGY COMPANY

/s/ Phillip S. Barnett

Phillip S. Barnett

Senior Vice President, Chief Financial Officer and

Treasurer

PECO Energy Company

BALTIMORE GAS AND ELECTRIC COMPANY

/s/ Carim V. Khouzami

Carim V. Khouzami

Vice President, Chief Financial Officer and Treasurer

Baltimore Gas and Electric Company

November 1, 2012

EXHIBIT INDEX

Exhibit No.	Description
99.1	Press release and earnings release attachments
99.2	Earnings conference call presentation slides

EX-99.1

Exhibit 99.1

Contact: JaCee Burnes Investor Relations 312-394-2948   Paul Adams Corporate Communications 410-470-4167 FOR IMMEDIATE RELEASE

EXELON ANNOUNCES THIRD QUARTER 2012 RESULTS;

RAISES FULL-YEAR OPERATING EARNINGS GUIDANCE RANGE

CHICAGO (Nov. 1, 2012) — Exelon Corporation (NYSE: EXC) announced third quarter 2012 consolidated earnings as follows:

	Third Quarter
	2012		2011
Adjusted (non-GAAP) Operating Results:
Net Income ($ millions)	$	658	$	743
Diluted Earnings per Share	$	0.77	$	1.12
GAAP Results:
Net Income ($ millions)	$	296	$	601
Diluted Earnings per Share	$	0.35	$	0.90

“We delivered strong financial performance during the third quarter and exceeded our quarterly guidance range thanks in large part to the management of our portfolio by Constellation, Exelon’s retail and wholesale marketing organization,” said Christopher M. Crane, Exelon’s president and CEO. “Based on our results through September and the ICC’s reversal of its ComEd pension asset decision in October, we are revising our full-year operating earnings guidance range upwards to $2.75 to $2.95 per share.”

Third Quarter Operating Results

Third quarter 2012 earnings include financial results for Constellation Energy and Baltimore Gas and Electric Company (BGE). Therefore, the composition of results of operations from 2012 and 2011 are not comparable for Exelon Generation Company, LLC (Generation), BGE and Exelon.

1

As shown in the table above, Exelon’s adjusted (non-GAAP) operating earnings declined to $0.77 per share in the third quarter of 2012 from $1.12 per share in the third quarter of 2011. Earnings in third quarter 2012 primarily reflected the following negative factors:

• Lower energy margins at Generation, resulting from decreased capacity pricing related to the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market, higher nuclear fuel costs and lower realized market prices for the sale of energy across all regions;

• Lower nuclear volume due to increased planned and unplanned outage days;

• Lower allowed ROE (return on equity) at ComEd;

• Higher operating and maintenance expenses, including increased labor, contracting and materials;

• Impact of increased average diluted common shares outstanding as a result of the merger; and

• Increased depreciation and amortization expense due to ongoing capital expenditures.

These factors were partially offset by:

• The addition of Constellation Energy’s contribution to Generation’s energy margins; and

• Decreased storm costs in the ComEd and PECO territories.

Adjusted (non-GAAP) operating earnings for the third quarter of 2012 do not include the following items (after tax) that were included in reported GAAP earnings:

	(in millions)			(per diluted share)
Mark-to-Market Impact of Economic Hedging Activities	$	19		$	0.02
Unrealized Gains Related to NDT (Nuclear Decommissioning Trust) Fund Investments	$	38		$	0.04
Plant Retirements and Divestitures	$	(193	)	$	(0.22	)
Asset Retirement Obligation	$	(6	)	$	(0.01	)
Constellation Merger and Integration Costs	$	(36	)	$	(0.04	)
Amortization of Commodity Contract Intangibles	$	(187	)	$	(0.21	)
Amortization of the Fair Value of Certain Debt	$	3			—

2

Adjusted (non-GAAP) operating earnings for the third quarter of 2011 do not include the following items (after tax) that were included in reported GAAP earnings:

	(in millions)			(per diluted share)
Mark-to-Market Impact of Economic Hedging Activities	$	(55	)	$	(0.08	)
Unrealized Losses Related to NDT Fund Investments	$	(76	)	$	(0.12	)
Plant Retirements and Divestitures	$	(2	)		—
Asset Retirement Obligation	$	(16	)	$	(0.02	)
Constellation Merger and Integration Costs	$	(11	)	$	(0.02	)
Other Acquisition Costs	$	(5	)	$	(0.01	)
Wolf Hollow Acquisition	$	23		$	0.03

2012 Earnings Outlook

Exelon revised upward its guidance range for 2012 adjusted (non-GAAP) operating earnings to $2.75 to $2.95 per share. Operating earnings guidance is based on the assumption of normal weather for the balance of the year and preliminary cost estimates for the impact of Hurricane Sandy.

The outlook for 2012 adjusted (non-GAAP) operating earnings for Exelon and its subsidiaries excludes the following items:

• Mark-to-market adjustments from economic hedging activities

• Unrealized gains and losses from NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements

• Financial impacts associated with the planned retirement of fossil generating units and the expected sale in the fourth quarter of 2012 of three generating stations as required by the merger

• Changes in decommissioning and other asset retirement obligation estimates

• Certain costs related to the merger and integration initiatives

• Costs incurred as part of the Maryland order approving the merger transaction

• Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date

• Costs incurred as part of a March 2012 settlement with the FERC

• Changes in state deferred tax rates resulting from a reassessment of apportionment of Exelon’s deferred taxes as a result of the merger

• Non-cash amortization of certain debt recorded at fair value at the merger date

• Other acquisition costs

• Significant impairments of assets, including goodwill

• Other unusual items

• Significant changes to GAAP

3

Third Quarter and Recent Highlights

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station, produced 34,581 gigawatt-hours (GWh) in the third quarter of 2012, compared with 36,045 GWh in the third quarter of 2011. The output data excludes the units owned by Constellation Energy Nuclear Group LLC (CENG). Excluding Salem and the units owned by CENG, the Exelon-operated nuclear plants achieved a 90.7 percent capacity factor for the third quarter of 2012, compared with 95.8 percent for the third quarter of 2011. The number of planned refueling outage days totaled 43 in the third quarter of 2012 versus 33 days in the third quarter of 2011. The number of non-refueling outage days at the Exelon-operated plants totaled 40 days in the third quarter of 2012, compared with three days in the third quarter of 2011.

• Fossil and Renewables Operations: The equivalent demand forced outage rate for Generation’s fossil fleet is 3.7 percent for the first three quarters of 2012, compared with 6.0 percent in the first three quarters of 2011. The 2012 results include former Constellation plants, exclusive of the Maryland Clean Coal plants to be sold, whereas 2011 data includes only legacy Exelon plants. The equivalent availability factor for the hydroelectric facilities was 91.9 percent in the third quarter of 2012, compared with 93.9 percent in the third quarter of 2011. The change was largely due to planned outages in July and August of 2012. The energy capture for the wind fleet was 94.4 percent in the third quarter of 2012, compared with 91.6 percent in the third quarter of 2011.

• ComEd Distribution Formula Rate Cases: The Illinois Commerce Commission (ICC) ruled on ComEd’s formula rate proceeding under the Electric Infrastructure Modernization Act (EIMA) on May 30, 2012 (May Order). EIMA is designed to provide for timely and regular recovery of actual costs to support a 10-year grid modernization program. As enacted by the General Assembly, EIMA expressly provides for recovery of certain categories of costs such as a return on equity tied to U.S. Treasury bonds and pension funding costs, and it also requires an annual revenue requirement reconciliation, or “true up,” to ensure customers pay no more or no less than ComEd’s true costs. In the proceeding covered by the May Order, ComEd had taken positions supporting a $59 million reduction in the annual revenue requirement being recovered in current rates (based on 2010 costs and 2011 plant additions), primarily reflecting a lower return on equity consistent with the provision of EIMA. The ICC’s May Order reduced the annual revenue requirements by $168 million, or approximately $110 million more than proposed by ComEd.

On October 3, 2012, the ICC issued its final Order on Remand (Rehearing Order) in ComEd’s expedited rehearing of specific items pursuant to EIMA. The Rehearing Order addressed three key conclusions reached in the ICC’s May Order: (1) ComEd’s pension asset recovery; (2) the rate of interest to affix to over or under recovered costs; and (3) the use of a year-end or an “average year” rate base in determining ComEd’s reconciliation revenue requirement.

4

In the Rehearing Order, the ICC adopted ComEd’s position on the return on its pension asset, resulting in an increase in ComEd’s annual revenue requirement of $35 million based on ComEd’s 2010 Pension Asset. The impact on the 2011 reconciliation and subsequent periods will incorporate the additional investment in the pension asset ComEd made in 2011. However, the ICC ruled against ComEd in affirming its decision to use (1) an average rate base in ComEd’s reconciliation revenue requirement; and (2) the ICC amended its prior order to provide a short-term debt rate as the appropriate interest rate to apply to under/over recoveries of incurred costs. ComEd filed a notice of appeal with the Illinois Appellate Court on Oct. 4, 2012 on the May Order and the Rehearing Order because the impact of the issues in the two orders would be nearly $100 million per year that ComEd would not be able to recover and subsequently reinvest in the distribution system in 2014 and beyond.

Pursuant to the distribution formula rate mechanism and the May Order, ComEd had recorded as of June 30, 2012 a net regulatory asset of $26 million, reflecting its best estimate of the probable increase in distribution rates under the annual reconciliation mechanism reflecting costs incurred in 2011 and the first six months of 2012. ComEd expects to record in the fourth quarter an increase in revenue of approximately $135 million pre-tax in 2012 consistent with the terms of the Rehearing Order.

• Maryland Clean Coal Asset Divestitures: On Aug. 8, 2012, Exelon reached an agreement to sell its three Maryland coal-fired power plants to Raven Power Holdings LLC (Raven Power), fulfilling its commitment to Maryland to divest the plants as part of its merger with Constellation Energy. The sale was required by the Federal Energy Regulatory Commission (FERC), U.S. Department of Justice (DOJ) and the Maryland Public Service Commission as part of Exelon’s merger approval. The three plants, known collectively as Maryland Clean Coal, include:

• Brandon Shores (coal) in Pasadena, Md.: 1,273 MW of installed capacity, two units

• C.P. Crane (coal and oil) in Middle River, Md.: 399 MW installed capacity, three units

• H.A. Wagner (coal, natural gas and oil) in Pasadena, Md.: 976 MW installed capacity, five units

Generation expects to receive proceeds of approximately $388 million in the fourth quarter less cash payments of approximately $32 million to Raven Power Holdings LLC over a twelve-month period beginning in June 2014. Generation expects to incur transaction costs of approximately $20 million through the closing of the transaction in the fourth quarter of 2012. The sale will generate approximately $225 million of cash tax benefits, of which $135 million will be realized in periods through 2013 with the balance to be received in later years. Therefore, Generation expects net after-tax cash sale proceeds of approximately $500 million through 2013 and approximately $65 million in 2014 and subsequent years. Exelon recorded a pre-tax loss of $278 million in the third quarter to reflect the difference between the estimated sale price and the carrying value of the plants. The impact of the loss has been excluded from Adjusted (Non-GAAP) Operating Earnings. All regulatory preconditions to closing this transaction have been met and required FERC authorizations have been received. The transaction is expected to close in the fourth quarter of this year.

5

• Qualified Facility Sales: On Aug. 21, 2012, Exelon closed on the sale of its ownership share of five California power plants – a total of 70 megawatts (MW) of generating capacity – to Tokyo-based IHI Corporation. The power plants joined Exelon’s generating portfolio following the company’s merger with Constellation Energy in March 2012. The five California power plants include:

• Chinese Station (biomass) in Jamestown, CA, in which Exelon owned a 9.9 MW share;

• Rio Bravo Fresno (biomass) in Fresno, CA, in which Exelon owned a 12 MW share;

• Rio Bravo Jasmin (coal) in Bakersfield, CA, in which Exelon owned a 17.5 MW share;

• Rio Bravo Poso (coal) in Bakersfield, CA, in which Exelon owned a 17.5 MW share;

• Rio Bravo Rocklin (biomass) in Lincoln, CA, in which Exelon owned a 12 MW share.

• Riverside 6 & Schuylkill 1 Retirements: On Oct. 31, 2012, Exelon Generation notified PJM Interconnection of its intention to permanently retire Schuylkill Generating Station Unit 1 by Feb. 1, 2013, and Riverside Generating Station Unit 6 by Jun. 1, 2014. Schuylkill Unit 1 is a 166 MW peaking oil unit located in Philadelphia, PA, which was placed in service in 1958. Riverside 6 is a 115 MW peaking gas/kerosene unit located in Baltimore, MD, which was placed in service in 1970. The units are being retired because they are no longer economic to operate due to their age, relatively high capital and operating costs and current market conditions. PJM has 30 days to review whether the proposed retirements of the units create transmission system reliability issues. Once PJM’s review is complete, Exelon will determine final retirement dates for the units.

• Texas ESP Application: On Aug. 28, 2012, Exelon halted efforts to gain initial federal regulatory approvals for new nuclear construction in Victoria County, TX. The company notified the Nuclear Regulatory Commission that it has withdrawn its Early Site Permit application for an 11,500-acre tract southeast of Victoria. The action is in response to low natural gas prices and economic and market conditions that have made construction of new merchant nuclear power plants in competitive markets uneconomical now and for the foreseeable future. Exelon originally submitted an application for a combined construction and operating license for the Victoria County site in 2008, but never made a decision to build a nuclear plant there. In 2010, the company applied for an Early Site Permit, a change in licensing strategy that allowed Exelon to continue with some aspects of site evaluation and regulatory approvals while deferring a construction decision for up to 20 years. The withdrawal of the license brings an end to all project activity.

6

• Constellation Solar Projects: In August 2012, Constellation announced two solar projects:

• On Aug. 14, 2012, Constellation announced that it will develop a 4.35-MW solar generation system for the Casa Grande Union High School District in Casa Grande, AZ. Constellation will own and operate the solar power system and the school district will purchase the electricity it generates under a 20-year power purchase agreement.

• On Aug. 29, 2012, Constellation announced the completion of a 16.1-MW (DC) grid-connected photovoltaic (PV) solar installation in Emmitsburg, MD., for the state of Maryland’s Generating Clean Horizons initiative. Constellation will own and operate the approximately $50 million solar facility on behalf of its customer, the State of Maryland. Electricity generated by the system is purchased by the state’s Department of General Services and the University System of Maryland under 20-year solar power purchase agreements with Constellation.

• Hedging Update: Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted-for capacity. The proportion of expected generation hedged as of Sept. 30, 2012, is 99 to 102 percent for 2012, 88 to 91 percent for 2013, 56 to 59 percent for 2014 and 21 to 24 percent for 2015. The primary objective of Exelon’s hedging program is to manage market risks and protect the value of its generation and its investment-grade balance sheet while preserving its ability to participate in improving long-term market fundamentals.

• Financing Activities:

• BGE: On Aug. 17, 2012, BGE issued $250 million in principal amount of its 2.80 percent Notes due 2022. BGE will use the net proceeds to repay outstanding commercial paper obligations and for general corporate purposes.

• PECO: On Sept. 17, 2012, PECO issued $350 million of First Mortgage Bonds, maturing on Sept. 15, 2022, with a coupon of 2.375 percent. PECO used a portion of the net proceeds from the sale of the bonds to pay at maturity $225 million aggregate principal amount of its 4.75 percent first mortgage bonds due Oct. 1, 2012, and the remaining proceeds were used for other general corporate purposes.

• ComEd: On Oct. 1, 2012, ComEd issued $350 million aggregate principal amount of its First Mortgage 3.800 percent Bonds, Series 113 due Oct. 1, 2042. ComEd will use the net proceeds from the sale of the bonds to repay outstanding commercial paper obligations and for general corporate purposes.

7

Operating Company Results

Generation consists of owned and contracted electric generating facilities and wholesale and retail customer supply of electric and natural gas products and services, including renewable energy products, risk management services and natural gas exploration and production activities.

Third quarter 2012 GAAP net income was $91 million, compared with $386 million in the third quarter of 2011. Adjusted (non-GAAP) operating earnings for the third quarter of 2011 and 2012 do not include various items (after tax) that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is in the table below:

($ millions)	3Q12			3Q11
Generation Adjusted (non-GAAP) Operating Earnings	$	458		$	522
Mark-to-Market Impact of Economic Hedging Activities	$	9		$	(55	)
Unrealized Gains/Losses Related to NDT Fund Investments	$	38		$	(76	)
Plant Retirements and Divestitures	$	(193	)	$	(2	)
Asset Retirement Obligation	$	(6	)	$	(18	)
Constellation Merger and Integration Costs	$	(31	)	$	(3	)
Amortization of Commodity Contract Intangibles	$	(187	)		—
Amortization of Fair Value of Certain Debt	$	3			—
Other Acquisition Costs		—		$	(5	)
Wolf Hollow Acquisition		—		$	23
Generation GAAP Net Income	$	91		$	386

Generation’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2012 decreased $64 million compared with the same quarter in 2011. This decrease primarily reflected:

• Lower energy margins at Generation, resulting from decreased capacity pricing related to RPM for the PJM market, higher nuclear fuel costs and lower realized market prices for the sale of energy across all regions;

• Lower nuclear volume due to increased planned and unplanned outage days;

• Higher operating and maintenance expenses; and

• Increased depreciation and amortization expense due to ongoing capital expenditures.

8

These items were partially offset by contribution to Generation’s energy margins from the addition of Constellation Energy to Generation’s operations.

Generation’s average realized margin on all electric sales, including sales to affiliates and excluding trading activity, was $25.96 per megawatt-hour (MWh) in the third quarter of 2012, compared with $39.19 per MWh in the third quarter of 2011.

ComEd consists of electricity transmission and distribution operations in northern Illinois.

ComEd recorded GAAP net income of $90 million in the third quarter of 2012, compared with net income of $112 million in the third quarter of 2011. Adjusted (non-GAAP) operating earnings for the third quarter of 2011 and 2012 do not include various items (after tax) that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is in the table below:

($ millions)	3Q12		3Q11
ComEd Adjusted (non-GAAP) Operating Earnings	$	90	$	113
Constellation Merger and Integration Costs		—	$	(1	)
ComEd GAAP Net Income	$	90	$	112

ComEd’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2012 were down $23 million from the same quarter in 2011, primarily due to decreased distribution revenues based on a lower allowed ROE as a result of a final order issued by the ICC on the 2011 performance based formula rate proceeding under the EIMA; this unfavorable item was partially offset by decreased storm costs in ComEd’s territory.

For the third quarter of 2012, cooling degree-days in the ComEd service territory were up 9.4 percent relative to the same period in 2011 and were 40.1 percent above normal. In the third quarter of 2012, heating degree-days in the ComEd service territory were down 27.2 percent relative to the same period in 2011 and were 10.1 percent below normal. Total retail electric deliveries increased 2.1 percent quarter over quarter.

Weather-normalized retail electric deliveries increased 0.2 percent in the third quarter of 2012 relative to 2011, reflecting increases in deliveries to residential and public authorities & railroads, partially offset by decreases in deliveries to both small and large commercial and industrial (C&I) customers. For ComEd, weather had no impact on third quarter 2012 earnings relative to 2011 and a favorable after-tax effect of $14 million relative to normal weather.

PECO consists of electricity transmission and distribution operations and retail natural gas distribution operations in southeastern Pennsylvania.

PECO’s GAAP net income in the third quarter of 2012 was $122 million, compared with $104 million in the third quarter of 2011. Adjusted (non-GAAP) Operating Earnings for the third quarter of 2011 and 2012 do not include various items (after tax) that were included in reported GAAP earnings. A reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income is in the table below:

($ millions)	3Q12			3Q11
PECO Adjusted (non-GAAP) Operating Earnings	$	124		$	103
Asset Retirement Obligation		—		$	2
Constellation Merger and Integration Costs	$	(2	)	$	(1	)
PECO GAAP Net Income	$	122		$	104

9

PECO’s Adjusted (non-GAAP) Operating Earnings in the third quarter of 2012 increased $21 million from the same quarter in 2011, primarily reflecting the effect of lower storm costs from 2011’s Hurricane Irene; this favorable item was partially offset by lower load.

For the third quarter of 2012, cooling degree-days in the PECO service territory were up 2.6 percent relative to the same period in 2011 and were 21.8 percent above normal. In the third quarter of 2012, heating degree-days in the PECO service territory were down 22.2 percent from 2011 and were 60.0 percent below normal. Total retail electric deliveries were down 2.3 percent quarter over quarter. On the retail gas side, deliveries in the third quarter of 2012 were down 4.4 percent from the third quarter of 2011.

Weather-normalized retail electric deliveries were down 3.6 percent in the third quarter of 2012 relative to 2011, reflecting declines in deliveries to all customer classes except public authorities and electric railroads. Weather-normalized gas deliveries were down 4.4 percent in the third quarter of 2012. For PECO, weather had a favorable after-tax effect of $3 million on third quarter 2012 earnings relative to 2011 and a favorable after-tax effect of $12 million relative to normal weather.

BGE consists of electricity transmission and distribution operations and retail natural gas distribution operations in central Maryland.

BGE’s GAAP net income in the third quarter of 2012 was $(4) million. The net income included after-tax costs of $1 million associated with the merger and integration initiatives. Excluding the effects of these items, BGE’s adjusted (non-GAAP) Operating Earnings in the third quarter of 2012 was $(3) million. The primary driver of BGE’s loss for the quarter was significant storm costs associated with the derecho storm.

Adjusted (non-GAAP) Operating Earnings

Adjusted (non-GAAP) operating earnings, which generally exclude significant one-time charges or credits that are not normally associated with ongoing operations, mark-to-market adjustments from economic hedging activities and unrealized gains and losses from NDT fund investments, are provided as a supplement to results reported in accordance with GAAP. Management uses such adjusted (non-GAAP) operating earnings measures internally to evaluate the company’s performance and manage its operations. Reconciliation of GAAP to adjusted (non-GAAP) operating earnings for historical periods is attached. Additional earnings release attachments, which include the reconciliation on pages 8 and 9 are posted on Exelon’s Web site: www.exeloncorp.com and have been furnished to the Securities and Exchange Commission on Form 8-K on November 1, 2012.

10

Cautionary Statements Regarding Forward-Looking Information

This news release contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon Generation Company, LLC (Registrants) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2011 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 18; (2) Constellation Energy Group’s 2011 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 12; (3) the Registrant’s Second Quarter 2012 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors and (b) Part I, Financial Information, ITEM 1. Financial Statements: Note 15; and (4) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this presentation. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this news release.

# # #

Exelon Corporation is the nation’s leading competitive energy provider, with approximately $33 billion in annual revenues. Headquartered in Chicago, Exelon has operations and business activities in 47 states, the District of Columbia and Canada. Exelon is the largest competitive U.S. power generator, with approximately 35,000 megawatts of owned capacity comprising one of the nation’s cleanest and lowest-cost power generation fleets. The company’s Constellation business unit provides energy products and services to approximately 100,000 business and public sector customers and approximately 1 million residential customers. Exelon’s utilities deliver electricity and natural gas to more than 6.6 million customers in central Maryland (BGE), northern Illinois (ComEd) and southeastern Pennsylvania (PECO).

11

Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations - Three Months Ended September 30, 2012 and 2011	1
Consolidating Statements of Operations - Nine Months Ended September 30, 2012 and 2011	2
Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Nine Months Ended September 30, 2012 and 2011	3
Business Segment Comparative Statements of Operations - PECO and BGE - Three and Nine Months Ended September 30, 2012 and 2011	4
Business Segment Comparative Statements of Operations - Other - Three and Nine Months Ended September 30, 2012 and 2011	5
Consolidated Balance Sheets - September 30, 2012 and December 31, 2011	6
Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2012 and 2011	7
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Three Months Ended September 30, 2012 and 2011	8
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Exelon - Nine Months Ended September 30, 2012 and 2011	9
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Three Months Ended September 30, 2012 and 2011	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings By Business Segment - Nine Months Ended September 30, 2012 and 2011	11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Generation - Three and Nine Months Ended September 30, 2012 and 2011	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - ComEd - Three and Nine Months Ended September 30, 2012 and 2011	13
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - PECO - Three and Nine Months Ended September 30, 2012 and 2011	14
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - BGE - Three Months Ended September 30, 2012 and March 12, 2012 Through September 30, 2012	15
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations - Other - Three and Nine Months Ended September 30, 2012 and 2011	16
Exelon Generation Statistics - Three Months Ended September 30, 2012, June 30, 2012, March 31, 2012, December 31, 2011 and September 30, 2011	17
Exelon Generation Statistics - Nine Months Ended September 30, 2012 and 2011	18
ComEd Statistics - Three and Nine Months Ended September 30, 2012 and 2011	19
PECO Statistics - Three and Nine Months Ended September 30, 2012 and 2011	20
BGE Statistics - Three Months Ended September 30, 2012 and March 12, 2012 Through September 30, 2012	21

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended September 30, 2012
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	4,017		$	1,484		$	806		$	720		$	(462	)	$	6,565
Operating expenses
Purchased power and fuel		2,122			678			326			373			(473	)		3,026
Operating and maintenance		1,415			350			199			201			(9	)		2,156
Depreciation, amortization, accretion and depletion		207			157			55			68			13			500
Taxes other than income		109			81			48			48			4			290
Total operating expenses		3,853			1,266			628			690			(465	)		5,972
Equity in earnings of unconsolidated affiliates		10			—			—			—			—			10
Operating income		174			218			178			30			3			603
Other income and deductions
Interest expense		(85	)		(74	)		(32	)		(35	)		(20	)		(246	)
Other, net		83			5			2			5			6			101
Total other income and deductions		(2	)		(69	)		(30	)		(30	)		(14	)		(145	)
Income (loss) before income taxes		172			149			148			—			(11	)		458
Income taxes		85			59			25			—			(8	)		161
Net income (loss)		87			90			123			—			(3	)		297
Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(4	)		—			1			4			—			1
Net income (loss) on common stock	$	91		$	90		$	122		$	(4	)	$	(3	)	$	296
	Three Months Ended September 30, 2011
	Generation			ComEd			PECO			BGE			Other (a)			Exelon Consolidated
Operating revenues	$	2,821		$	1,784		$	946		$	—		$	(297	)	$	5,254
Operating expenses
Purchased power and fuel		1,071			932			464			—			(346	)		2,121
Operating and maintenance		790			396			219			—			8			1,413
Depreciation, amortization, accretion and depletion		139			135			51			—			7			332
Taxes other than income		67			78			59			—			3			207
Total operating expenses		2,067			1,541			793			—			(328	)		4,073
Operating income		754			243			153			—			31			1,181
Other income and deductions
Interest expense		(37	)		(86	)		(34	)		—			(25	)		(182	)
Other, net		(164	)		16			3			—			3			(142	)
Total other income and deductions		(201	)		(70	)		(31	)		—			(22	)		(324	)
Income before income taxes		553			173			122						9			857
Income taxes		167			61			17			—			10			255
Net income (loss)		386			112			105			—			(1	)		602
Preferred security dividends		—			—			1			—			—			1
Net income (loss) on common stock	$	386		$	112		$	104		$	—		$	(1	)	$	601

(a) Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

1

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Nine Months Ended September 30, 2012 (a)
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	10,509		$	4,154		$	2,396		$	1,388		$	(1,242	)	$	17,205
Operating expenses
Purchased power and fuel		5,018			1,886			1,033			727			(1,266	)		7,398
Operating and maintenance		3,756			1,000			574			423			196			5,949
Depreciation, amortization, accretion and depletion		564			458			161			157			36			1,376
Taxes other than income		272			224			122			104			15			737
Total operating expenses		9,610			3,568			1,890			1,411			(1,019	)		15,460
Equity in losses of unconsolidated affiliates		(69	)		—			—			—			—			(69	)
Operating income (loss)		830			586			506			(23	)		(223	)		1,676
Other income and deductions
Interest expense		(223	)		(230	)		(94	)		(77	)		(73	)		(697	)
Other, net		185			12			6			14			36			253
Total other income and deductions		(38	)		(218	)		(88	)		(63	)		(37	)		(444	)
Income (loss) before income taxes		792			368			418			(86	)		(260	)		1,232
Income taxes		373			149			118			(37	)		(158	)		445
Net income (loss)		419			219			300			(49	)		(102	)		787
Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends		(6	)		—			3			8			—			5
Net income (loss) on common stock	$	425		$	219		$	297		$	(57	)	$	(102	)	$	782
	Nine Months Ended September 30, 2011
	Generation			ComEd			PECO			BGE			Other (b)			Exelon Consolidated
Operating revenues	$	7,919		$	4,694		$	2,942		$	—		$	(850	)	$	14,705
Operating expenses
Purchased power and fuel		2,795			2,436			1,506			—			(901	)		5,836
Operating and maintenance		2,306			930			597			—			30			3,863
Depreciation, amortization, accretion and depletion		416			405			150			—			16			987
Taxes other than income		199			226			165			—			12			602
Total operating expenses		5,716			3,997			2,418			—			(843	)		11,288
Operating income (loss)		2,203			697			524			—			(7	)		3,417
Other income and deductions
Interest expense		(128	)		(257	)		(102	)		—			(58	)		(545	)
Other, net		(12	)		24			11			—			31			54
Total other income and deductions		(140	)		(233	)		(91	)		—			(27	)		(491	)
Income (loss) before income taxes		2,063			464			433			—			(34	)		2,926
Income taxes		738			169			119			—			8			1,034
Net income (loss)		1,325			295			314			—			(42	)		1,892
Preferred security dividends		—			—			3			—			—			3
Net income (loss) on common stock	$	1,325		$	295		$	311		$	—		$	(42	)	$	1,889

(a) Includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.

(b) Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended September 30,									Nine Months Ended September 30,
	2012			2011			Variance			2012 (a)			2011			Variance
Operating revenues	$	4,017		$	2,821		$	1,196		$	10,509		$	7,919		$	2,590
Operating expenses
Purchased power and fuel		2,122			1,071			1,051			5,018			2,795			2,223
Operating and maintenance		1,415			790			625			3,756			2,306			1,450
Depreciation, amortization, accretion and depletion		207			139			68			564			416			148
Taxes other than income		109			67			42			272			199			73
Total operating expenses		3,853			2,067			1,786			9,610			5,716			3,894
Equity in earnings (losses) of unconsolidated affiliates		10			—			10			(69	)		—			(69	)
Operating income		174			754			(580	)		830			2,203			(1,373	)
Other income and deductions
Interest expense		(85	)		(37	)		(48	)		(223	)		(128	)		(95	)
Other, net		83			(164	)		247			185			(12	)		197
Total other income and deductions		(2	)		(201	)		199			(38	)		(140	)		102
Income before income taxes		172			553			(381	)		792			2,063			(1,271	)
Income taxes		85			167			(82	)		373			738			(365	)
Net income		87			386			(299	)		419			1,325			(906	)
Net loss attributable to noncontrolling interests		(4	)		—			(4	)		(6	)		—			(6	)
Net income on common stock	$	91		$	386		$	(295	)	$	425		$	1,325		$	(900	)

(a) Includes financial results for Constellation beginning on March 12, 2012, the date the merger was completed.

	ComEd
	Three Months Ended September 30,									Nine Months Ended September 30,
	2012			2011			Variance			2012			2011			Variance
Operating revenues	$	1,484		$	1,784		$	(300	)	$	4,154		$	4,694		$	(540	)
Operating expenses
Purchased power		678			932			(254	)		1,886			2,436			(550	)
Operating and maintenance		350			396			(46	)		1,000			930			70
Depreciation and amortization		157			135			22			458			405			53
Taxes other than income		81			78			3			224			226			(2	)
Total operating expenses		1,266			1,541			(275	)		3,568			3,997			(429	)
Operating income		218			243			(25	)		586			697			(111	)
Other income and deductions
Interest expense		(74	)		(86	)		12			(230	)		(257	)		27
Other, net		5			16			(11	)		12			24			(12	)
Total other income and deductions		(69	)		(70	)		1			(218	)		(233	)		15
Income before income taxes		149			173			(24	)		368			464			(96	)
Income taxes		59			61			(2	)		149			169			(20	)
Net income	$	90		$	112		$	(22	)	$	219		$	295		$	(76	)

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended September 30,									Nine Months Ended September 30,
	2012			2011			Variance			2012			2011			Variance
Operating revenues	$	806		$	946		$	(140	)	$	2,396		$	2,942		$	(546	)
Operating expenses
Purchased power and fuel		326			464			(138	)		1,033			1,506			(473	)
Operating and maintenance		199			219			(20	)		574			597			(23	)
Depreciation and amortization		55			51			4			161			150			11
Taxes other than income		48			59			(11	)		122			165			(43	)
Total operating expenses		628			793			(165	)		1,890			2,418			(528	)
Operating income		178			153			25			506			524			(18	)
Other income and deductions
Interest expense		(32	)		(34	)		2			(94	)		(102	)		8
Other, net		2			3			(1	)		6			11			(5	)
Total other income and deductions		(30	)		(31	)		1			(88	)		(91	)		3
Income before income taxes		148			122			26			418			433			(15	)
Income taxes		25			17			8			118			119			(1	)
Net income		123			105			18			300			314			(14	)
Preferred security dividends		1			1			—			3			3			—
Net income on common stock	$	122		$	104		$	18		$	297		$	311		$	(14	)
	BGE
	Three Months Ended September 30,									March 12, 2012 through September 30,
	2012			2011			Variance			2012			2011			Variance
Operating revenues	$	720		$	—		$	720		$	1,388		$	—		$	1,388
Operating expenses
Purchased power and fuel		373			—			373			727			—			727
Operating and maintenance		201			—			201			423			—			423
Depreciation and amortization		68			—			68			157			—			157
Taxes other than income		48			—			48			104			—			104
Total operating expenses		690			—			690			1,411			—			1,411
Operating income (loss)		30			—			30			(23	)		—			(23	)
Other income and deductions
Interest expense		(35	)		—			(35	)		(77	)		—			(77	)
Other, net		5			—			5			14			—			14
Total other income and deductions		(30	)		—			(30	)		(63	)		—			(63	)
Loss before income taxes		—			—			—			(86	)		—			(86	)
Income taxes		—			—			—			(37	)		—			(37	)
Net loss		—			—			—			(49	)		—			(49	)
Preference stock dividends		4			—			4			8			—			8
Net loss on common stock	$	(4	)	$	—		$	(4	)	$	(57	)	$	—		$	(57	)

4

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2012			2011			Variance			2012 (b)			2011			Variance
Operating revenues	$	(462	)	$	(297	)	$	(165	)	$	(1,242	)	$	(850	)	$	(392	)
Operating expenses
Purchased power and fuel		(473	)		(346	)		(127	)		(1,266	)		(901	)		(365	)
Operating and maintenance		(9	)		8			(17	)		196			30			166
Depreciation and amortization		13			7			6			36			16			20
Taxes other than income		4			3			1			15			12			3
Total operating expenses		(465	)		(328	)		(137	)		(1,019	)		(843	)		(176	)
Operating income (loss)		3			31			(28	)		(223	)		(7	)		(216	)
Other income and deductions
Interest expense		(20	)		(25	)		5			(73	)		(58	)		(15	)
Other, net		6			3			3			36			31			5
Total other income and deductions		(14	)		(22	)		8			(37	)		(27	)		(10	)
Income (loss) before income taxes		(11	)		9			(20	)		(260	)		(34	)		(226	)
Income taxes		(8	)		10			(18	)		(158	)		8			(166	)
Net loss	$	(3	)	$	(1	)	$	(2	)	$	(102	)	$	(42	)	$	(60	)

(a) Other primarily includes eliminating and consolidating adjustments, Exelon's corporate operations, shared service entities and other financing and investment activities.

(b) Includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.

5

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited)

(in millions)

	September 30, 2012 (a)			December 31, 2011
ASSETS
Current assets
Cash and cash equivalents	$	1,602		$	1,016
Cash and cash equivalents of variable interest entities		98			—
Restricted cash and investments		73			40
Restricted cash and investments of variable interest entities		67			—
Accounts receivable, net
Customer		2,835			1,613
Other		1,216			1,000
Accounts receivable, net, variable interest entities		225			—
Mark-to-market derivative assets		928			432
Unamortized energy contract assets		1,141			13
Inventories, net
Fossil fuel		264			208
Materials and supplies		767			656
Deferred income taxes		254			—
Regulatory assets		786			390
Other		1,072			345
Total current assets		11,328			5,713
Property, plant and equipment, net		43,914			32,570
Deferred debits and other assets
Regulatory assets		6,192			4,518
Nuclear decommissioning trust (NDT) funds		7,140			6,507
Investments		838			751
Investments in affiliates		371			15
Investment in CENG		1,908			—
Goodwill		2,625			2,625
Mark-to-market derivative assets		1,039			650
Unamortized energy contracts assets		1,191			388
Pledged assets for Zion Station decommissioning		631			734
Other		1,176			524
Total deferred debits and other assets		23,111			16,712
Total assets	$	78,353		$	54,995
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	60		$	163
Short-term notes payable - accounts receivable agreement		225			225
Long-term debt due within one year		1,049			828
Long-term debt of variable interest entities due within one year		70			—
Accounts payable		2,359			1,444
Accounts payable of variable interest entities		132			—
Accrued expenses		1,502			1,255
Deferred income taxes		52			1
Regulatory liabilities		299			197
Dividends payable		4			349
Mark-to-market derivative liabilities		521			112
Unamortized energy contract liabilities		523			—
Other		974			560
Total current liabilities		7,770			5,134
Long-term debt		17,050			11,799
Long-term debt to financing trusts		649			390
Long-term debt of variable interest entity		546			—
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits		11,600			8,253
Asset retirement obligations		4,866			3,884
Pension obligations		2,575			2,194
Non-pension postretirement benefit obligations		2,946			2,263
Spent nuclear fuel obligation		1,020			1,019
Regulatory liabilities		4,000			3,627
Mark-to-market derivative liabilities		407			126
Unamortized energy contract liabilities		621			—
Payable for Zion Station decommissioning		422			563
Other		1,691			1,268
Total deferred credits and other liabilities		30,148			23,197
Total liabilities		56,163			40,520
Commitments and contingencies
Preferred securities of subsidiary		87			87
Shareholders’ equity
Common stock		16,594			9,107
Treasury stock, at cost		(2,327	)		(2,327	)
Retained earnings		9,959			10,055
Accumulated other comprehensive loss, net		(2,405	)		(2,450	)
Total shareholders’ equity		21,821			14,385
BGE preference stock not subject to mandatory redemption		193			—
Noncontrolling interest		89			3
Total equity		22,103			14,388
Total liabilities and shareholders’ equity	$	78,353		$	54,995

(a) Includes the financial information of Constellation and BGE.

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Nine Months Ended September 30,
	2012 (a)			2011
Cash flows from operating activities
Net income	$	787		$	1,892
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, accretion and depletion including nuclear fuel and energy contract amortization		2,909			1,702
Impairment of long-lived assets		278			—
Deferred income taxes and amortization of investment tax credits		263			1,008
Net fair value changes related to derivatives		(377	)		360
Net realized and unrealized gains on NDT fund investments		(142	)		90
Other non-cash operating activities		1,235			703
Changes in assets and liabilities:
Accounts receivable		240			3
Inventories		12			(44	)
Accounts payable, accrued expenses and other current liabilities		(837	)		(400	)
Option premiums (paid) received, net		(122	)		59
Counterparty collateral received (posted), net		408			(807	)
Income taxes		465			532
Pension and non-pension postretirement benefit contributions		(131	)		(2,089	)
Other assets and liabilities		(431	)		(92	)
Net cash flows provided by operating activities		4,557			2,917
Cash flows from investing activities
Capital expenditures		(4,145	)		(2,972	)
Proceeds from nuclear decommissioning trust fund sales		6,262			3,120
Investment in nuclear decommissioning trust funds		(6,422	)		(3,293	)
Acquisitions		—			(380	)
Cash acquired from Constellation		964			—
Proceeds from sales of investments		26			—
Purchases of investments		(13	)		—
Change in restricted cash		(38	)		(532	)
Other investing activities		41			26
Net cash flows used in financing activities		(3,325	)		(4,031	)
Cash flows from financing activities
Changes in short-term debt		(139	)		462
Issuance of long-term debt		1,558			1,199
Retirement of long-term debt		(731	)		(3	)
Dividends paid on common stock		(1,226	)		(1,044	)
Dividends paid to former Constellation shareholders		(51	)		—
Proceeds from employee stock plans		61			26
Other financing activities		(20	)		(67	)
Net cash flows (used in) provided by financing activities		(548	)		573
Increase (decrease) in cash and cash equivalents		684			(541	)
Cash and cash equivalents at beginning of period		1,016			1,612
Cash and cash equivalents at end of period	$	1,700		$	1,071

(a) Includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.

7

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations

(unaudited)

(in millions, except per share data)

	Three Months Ended September 30, 2012 (a)									Three Months Ended September 30, 2011
							Adjusted									Adjusted
	GAAP (b)			Adjustments			Non-GAAP			GAAP (b)			Adjustments			Non-GAAP
Operating revenues	$	6,565		$	464	(c),(d),(e)	$	7,029		$	5,254		$	(33	)(c),(j)	$	5,221
Operating expenses
Purchased power and fuel		3,026			278	(c),(d),(e)		3,304			2,121			(93	)(c),(d)		2,028
Operating and maintenance		2,156			(378	(c),(e),(f),  )(g)		1,778			1,413			(65	(c),(f),(g),  )(j),(k)		1,348
Depreciation, amortization, accretion and depletion		500			(13	)(c),(f)		487			332			(19	)(c)		313
Taxes other than income		290			(4	)(c)		286			207			—			207
Total operating expenses		5,972			(117	)		5,855			4,073			(177	)		3,896
Equity in earnings of unconsolidated affiliates		10			50	(e)		60			—			—			—
Operating income		603			631			1,234			1,181			144			1,325
Other income and deductions
Interest expense		(246	)		(2	)(f),(h)		(248	)		(182	)		—			(182	)
Other, net		101			(60	)(c),(f),(i)		41			(142	)		181	(i)		39
Total other income and deductions		(145	)		(62	)		(207	)		(324	)		181			(143	)
Income before income taxes		458			569			1,027			857			325			1,182
Income taxes		161			207	(c),(d),(e),   (f),(g),(h),(i)		368			255			183	(c),(d),(f),   (g),(i),(j),(k)		438
Net income		297			362			659			602			142			744
Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends		1			—			1			1			—			1
Net income on common stock	$	296		$	362		$	658		$	601		$	142		$	743
Effective tax rate		35.2	%					35.8	%		29.8	%					37.1	%
Earnings per average common share
Basic	$	0.35		$	0.42		$	0.77		$	0.91		$	0.21		$	1.12
Diluted	$	0.35		$	0.42		$	0.77		$	0.90		$	0.22		$	1.12
Average common shares outstanding
Basic		854						854			663						663
Diluted		857						857			665						665

Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Plant retirements and divestitures (c)	$	0.22		$	—
Mark-to-market impact of economic hedging activities (d)		(0.02	)		0.08
Amortization of commodity contract intangibles (e)		0.21			—
Constellation merger and integration costs (f)		0.04			0.02
Asset retirement obligation (g)		0.01			0.02
Amortization of the fair value of certain debt (h)		—			—
Unrealized (gains) losses related to NDT fund investments (i)		(0.04	)		0.12
Wolf Hollow acquisition (j)		—			(0.03	)
Other acquisition costs (k)		—			0.01
Total adjustments	$	0.42		$	0.22

(a) Includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed.

(b) Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(c) Adjustment to exclude costs associated with the retirement of fossil generating units, the impacts of the FERC approved reliability-must-run rate schedule and the impact associated with the expected sale in the fourth quarter of 2012 of three generating stations associated with certain of the regulatory approvals required for the merger.

(d) Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

(e) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date.

(f) Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(g) Adjustment to exclude the increase in Generation’s decommissioning obligation for spent nuclear fuel at retired nuclear units.

(h) Adjustment to exclude the non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in 2013.

(i) Adjustment to exclude the unrealized losses in 2011 and gains in 2012 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(j) Adjustment to exclude the non-cash bargain purchase gain (negative goodwill) associated with the acquisition of Wolf Hollow, net of acquisition costs.

(k) Adjustment to exclude certain costs associated with Exelon’s acquisition of Antelope Valley Solar Ranch One (AVSR) in 2011.

8

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Consolidated Statements of Operations

(unaudited)

(in millions, except per share data)

	Nine Months Ended September 30, 2012 (a)									Nine Months Ended September 30, 2011
							Adjusted									Adjusted
	GAAP (b)			Adjustments			Non-GAAP			GAAP (b)			Adjustments			Non-GAAP
Operating revenues	$	17,205		$	1,024	(c),(d),(e),(f)	$	18,229		$	14,705		$	(42	)(c),(n)	$	14,663
Operating expenses
Purchased power and fuel		7,398			540	(c),(d),(e),(g)		7,938			5,836			(366	)(d)		5,470
Operating and maintenance		5,949			(1,051	(c),(e),(f),  )(g),(h),(i),(j)		4,898			3,863			(82	(c),(g),(i),  )(j),(n),(o)		3,781
Depreciation, amortization, accretion and depletion		1,376			(43	)(c),(g)		1,333			987			(65	)(c)		922
Taxes other than income		737			(6	)(c),(f)		731			602			—			602
Total operating expenses		15,460			(560	)		14,900			11,288			(513	)		10,775
Equity in earnings (losses) of unconsolidated affiliates		(69	)		110	(e),(g)		41			—			—			—
Operating income		1,676			1,694			3,370			3,417			471			3,888
Other income and deductions
Interest expense		(697	)		(8	)(g),(k)		(705	)		(545	)		—			(545	)
Other, net		253			(73	)(c),(g),(l)		180			54			94	(l),(n)		148
Total other income and deductions		(444	)		(81	)		(525	)		(491	)		94			(397	)
Income before income taxes		1,232			1,613			2,845			2,926			565			3,491
Income taxes		445			612	(c),(d),(e),(f),  (g),(h),(i),(j),  (k),(l),(m)		1,057			1,034			235	(c),(d),(g),(i),   (j),(l),(n),   (o),(p)		1,269
Net income on common stock		787			1,001			1,788			1,892			330			2,222
Net loss attributable to noncontrolling interests, preferred security dividends and preference stock dividends		5			—			5			3			—			3
Net income	$	782		$	1,001		$	1,783		$	1,889		$	330		$	2,219
Effective tax rate		36.1	%					37.2	%		35.3	%					36.4	%
Earnings per average common share
Basic	$	0.97		$	1.25		$	2.22		$	2.85		$	0.50		$	3.35
Diluted	$	0.97		$	1.24		$	2.21		$	2.84		$	0.50		$	3.34
Average common shares outstanding
Basic		804						804			663						663
Diluted		806						806			664						664
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Plant retirements and divestitures (c)				$	0.25								$	0.04
Mark-to-market impact of economic hedging activities (d)					(0.23	)								0.34
Amortization of commodity contract intangibles (e)					0.68									—
Maryland commitments (f)					0.28									—
Constellation merger and integration costs (g)					0.26									0.04
FERC settlement (h)					0.22									—
Other acquisition costs (i)					—									0.01
Asset retirement obligation (j)					0.01									0.02
Amortization of the fair value of certain debt (k)					(0.01	)								—
Unrealized (gains) losses related to NDT fund investments (l)					(0.07	)								0.07
Reassessment of state deferred income taxes (m)					(0.15	)								—
Wolf Hollow acquisition (n)					—									(0.03	)
Recovery of costs pursuant to the 2011 distribution rate case order (o)					—									(0.03	)
Charge resulting from Illinois tax rate change legislation (p)					—									0.04
Total adjustments				$	1.24								$	0.50

(a) Includes financial results for Constellation Energy including BGE, beginning on March 12, 2012, the date the acquisition was completed.

(b) Results reported in accordance with GAAP.

(c) Adjustment to exclude costs associated with the retirement of fossil generating units, the impacts of the FERC approved reliability-must-run rate schedule, and the impact associated with the expected sale in the fourth quarter of 2012 of three generation stations associated with certain of the regulatory approvals required for the merger.

(d) Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities.

(e) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date.

(f) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.

(g) Adjustment to exclude certain activities associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(h) Adjustment to exclude costs associated with the March 2012 settlement with the FERC.

(i) Adjustment to exclude certain costs associated with various acquisitions.

(j) Adjustment to exclude the increase in Generation’s decommissioning obligation for spent nuclear fuel and the decrease in PECO’s asset retirement obligation.

(k) Adjustment to exclude the non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in 2013.

(l) Adjustment to exclude the unrealized gains in 2011 and losses in 2012 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(m) Adjustment to exclude a one-time, non-cash benefit associated with a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s deferred taxes as a result of the merger.

(n) Adjustment to exclude the non-cash bargain purchase gain (negative goodwill) associated with the acquisition of Wolf Hollow, net of acquisition costs.

(o) Adjustment to exclude one-time benefits for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

(p) Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

9

EXELON CORPORATION (a)

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended September 30, 2012 and 2011

	Exelon
	Earnings per
	Diluted Share			Generation			ComEd			PECO			BGE			Other (b)			Exelon
2011 GAAP Earnings (Loss)	$	0.90		$	386		$	112		$	104		$	—		$	(1	)	$	601
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.08			55			—			—			—			—			55
Unrealized Losses Related to NDT Fund Investments (1)		0.12			76			—			—			—			—			76
Plant Retirements and Divestitures (2)		—			2			—			—			—			—			2
Asset Retirement Obligation (3)		0.02			18			—			(2	)		—			—			16
Constellation Merger and Integration Costs (4)		0.02			3			1			1			—			6			11
Other Acquisition Costs		0.01			5			—			—			—			—			5
Wolf Hollow Acquisition (5)		(0.03	)		(23	)		—			—			—			—			(23	)
2011 Adjusted (non-GAAP) Operating Earnings		1.12			522			113			103			—			5			743
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (6)		(0.03	)		(24	)		—			—			—			—			(24	)
Nuclear Fuel Costs (7)		(0.01	)		(13	)		—			—			—			—			(13	)
Capacity Pricing (8)		—			2			—			—			—			—			2
Market and Portfolio Conditions (9)		0.22			185			—			—			—			—			185
Transmission Upgrades (10)		—			30			—			—			—			(30	)		—
ComEd, PECO and BGE Margins:
Weather		—			—			—			3			—	(c)		—			3
Load		(0.01	)		—			1			(7	)		—	(c)		—			(6	)
Other Energy Delivery (11)		0.21			—			(29	)		3			208			—			182
Operating and Maintenance Expense:
Labor, Contracting and Materials (12)		(0.25	)		(143	)		(14	)		7			(60	)		—			(210	)
Planned Nuclear Refueling Outages		—			(3	)		—			—			—			—			(3	)
Pension and Non-Pension Postretirement Benefits (13)		(0.03	)		(8	)		(9	)		(2	)		(7	)		(3	)		(29	)
Other Operating and Maintenance (14)		(0.03	)		(41	)		50			13			(53	)		7			(24	)
Depreciation and Amortization Expense (15)		(0.12	)		(46	)		(14	)		(3	)		(40	)		(4	)		(107	)
Equity in Earnings of Unconsolidated Affiliates (16)		0.04			38			—			—			—			—			38
Income Taxes (17)		0.01			8			(7	)		(2	)		—			10			9
Interest Expense, Net (18)		(0.05	)		(34	)		1			1			(21	)		7			(46	)
Other		(0.05	)		(15	)		(2	)		8			(30	)		(3	)		(42	)
Share Differential (19)		(0.25	)		—			—			—			—			—			—
2012 Adjusted (non-GAAP) Operating Earnings (Loss)		0.77			458			90			124			(3	)		(11	)		658
2012 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.02			9			—			—			—			10			19
Unrealized Gains Related to NDT Fund Investments (1)		0.04			38			—			—			—			—			38
Plant Retirements and Divestitures (2)		(0.22	)		(193	)		—			—			—			—			(193	)
Asset Retirement Obligation (3)		(0.01	)		(6	)		—			—			—			—			(6	)
Constellation Merger and Integration Costs (4)		(0.04	)		(31	)		—			(2	)		(1	)		(2	)		(36	)
Amortization of Commodity Contract Intangibles (20)		(0.21	)		(187	)		—			—			—			—			(187	)
Amortization of the Fair Value of Certain Debt (21)		—			3			—			—			—			—			3
2012 GAAP Earnings (Loss)	$	0.35		$	91		$	90		$	122		$	(4	)	$	(3	)	$	296

(a) For the three months ended September 30, 2012, includes financial results for Constellation and BGE. Therefore, the results of operations from 2012 and 2011 are not comparable for Generation, BGE, Other and Exelon. The explanations below identify any significant or unusual items affecting the results of operations.

(b) Other primarily includes eliminating and consolidating adjustments, Exelon's corporate operations, shared service entities and other financing and investment activities.

(c) As approved by the Maryland PSC, BGE records a monthly adjustment to residential and the majority of its commercial and industrial customers to eliminate the effect of abnormal weather and usage patterns per customer on distribution volumes.

(1) Reflects the impact of unrealized losses in 2011 and unrealized gains in 2012 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2) For 2012, primarily reflects the impact associated with the expected sale in the fourth quarter of 2012 of three generating stations associated with certain of the regulatory approvals required for the merger. For 2011, primarily reflects incremental accelerated depreciation associated with the retirement of four fossil generating units and compensation for operating two of the units past their planned retirement date under a FERC-approved reliability-must-run rate schedule.

(3) Primarily reflects an increase in Generation’s decommissioning obligation for spent nuclear fuel at retired nuclear units.

(4) Reflects certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(5) Primarily reflects a non-cash bargain purchase gain (negative goodwill) in 2011 in connection with the acquisition of Wolf Hollow, net of acquisition costs.

(6) Primarily reflects the impact of increased planned and unplanned nuclear outage days in 2012, excluding Constellation Energy Nuclear Group, LLC (CENG).

(7) Primarily reflects the impact of higher nuclear fuel prices, excluding CENG.

(8) Primarily reflects the addition of Constellation’s financial results in 2012, offset by the impact of decreased capacity prices related to the Reliability Pricing Model (RPM) for the PJM Interconnection, LLC (PJM) market.

(9) Primarily reflects the addition of Constellation’s financial results in 2012, partially offset by the impact of decreased realized market prices for the sale of energy across all regions.

(10) Reflects intercompany expense in 2011 at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

(11) For ComEd, primarily reflects decreased distribution revenue pursuant to the performance based formula rate and decreased cost recovery for regulatory required programs (completely offset in operating and maintenance expense).

(12) Primarily reflects the addition of Constellation and BGE's financial results in 2012 and the impacts of increased wages and other benefits and increased contracting expenses (exclusive of planned nuclear refueling outages and incremental storm costs). At ComEd, primarily reflects increased contracting expenses resulting from new projects related to EIMA. At PECO, primarily reflects a decrease in contracting expenses.

(13) The increase in pension and OPEB costs primarily reflect the impact of lower actuarially assumed discount rates and expected return on assets for 2012 as compared to 2011.

(14) Primarily reflects the addition of Constellation and BGE's financial results in 2012 and the impact of storm costs in the BGE service territory, partially offset by decreased storm costs in the ComEd and PECO service territories and decreased costs at ComEd associated with regulatory required programs (completely offset by decreased other energy delivery revenues at ComEd).

(15) Includes increased depreciation expense across the operating companies due to ongoing capital expenditures and the non-cash amortization of intangible assets at Generation primarily related to the trade name and retail relationships recorded at fair value at the merger date.

(16) Primarily reflects the equity in earnings in CENG, partially offset by the non-cash amortization of the fair value basis difference recorded at the merger date.

(17) At Generation, primarily reflects an increase in investment tax credits attributable to AVSR, partially offset by a 2012 reduction in manufacturing deduction benefits. At PECO, primarily reflects a 2011 benefit for the electric transmission and distribution property repairs deduction, offset by a 2012 gas property repairs deduction.

(18) Primarily reflects the addition of Constellation and BGE's financial results in 2012 and the impact of higher interest expense at Generation and BGE due to higher outstanding debt.

(19) Reflects the impact on earnings per share due to the increase in Exelon's average diluted common shares outstanding as a result of the merger.

(20) Represents the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date.

(21) Represents the non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in 2013.

10

EXELON CORPORATION (a)

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Nine Months Ended September 30, 2012 and 2011

	Exelon Earnings  per Diluted Share			Generation			ComEd			PECO			BGE			Other (b)			Exelon
2011 GAAP Earnings (Loss)	$	2.84		$	1,325		$	295		$	311		$	—		$	(42	)	$	1,889
2011 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.34			219			—			—			—			—			219
Unrealized Losses Related to NDT Fund Investments (1)		0.07			46			—			—			—			—			46
Plant Retirements and Divestitures (2)		0.04			29			—			—			—			—			29
Asset Retirement Obligation (3)		0.02			18			—			(2	)		—			—			16
Non-Cash Charge Resulting From Illinois Tax Rate Change Legislation (4)		0.04			21			4			—			—			4			29
Recovery of Costs Pursuant to the 2011 Distribution Rate Case Order (5)		(0.03	)		—			(17	)		—			—			—			(17	)
Constellation Merger and Integration Costs (6)		0.04			3			1			1			—			21			26
Other Acquisition Costs		0.01			5			—			—			—			—			5
Wolf Hollow Acquisition (7)		(0.03	)		(23	)		—			—			—			—			(23	)
2011 Adjusted (non-GAAP) Operating Earnings (Loss)		3.34			1,643			283			310			—			(17	)		2,219
Year Over Year Effects on Earnings:
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume		—			—			—			—			—			—			—
Nuclear Fuel Costs (8)		(0.06	)		(45	)		—			—			—			—			(45	)
Capacity Pricing (9)		(0.13	)		(102	)		—			—			—			—			(102	)
Market and Portfolio Conditions (10)		0.49			394			—			—			—			—			394
Transmission Upgrades (11)		—			34			—			—			—			(34	)		—
ComEd, PECO and BGE Margins:
Weather		(0.04	)		—			—			(34	)		—	(c)		—			(34	)
Load		(0.02	)		—			(2	)		(15	)		—	(c)		—			(17	)
Discrete Impacts of the 2012 Distribution Formula Rate Order (12)		(0.06	)		—			(52	)		—			—			—			(52	)
Other Energy Delivery (13)		0.66			—			71			—			464			—			535
Discrete Impacts of the 2011 Distribution Rate Case Order (14)		(0.03	)		—			(22	)		—			—			—			(22	)
Operating and Maintenance Expense:
Labor, Contracting and Materials (15)		(0.59	)		(324	)		(40	)		17			(130	)		—			(477	)
Planned Nuclear Refueling Outages (16)		0.02			19			—			—			—			—			19
Pension and Non-Pension Postretirement Benefits (17)		(0.09	)		(24	)		(19	)		(5	)		(14	)		(8	)		(70	)
Other Operating and Maintenance (18)		(0.18	)		(133	)		36			14			(90	)		22			(151	)
Depreciation and Amortization Expense (19)		(0.31	)		(107	)		(32	)		(7	)		(94	)		(12	)		(252	)
2011 Nuclear Decommissioning Trust Fund Special Transfer Tax Deduction (20)		(0.06	)		(46	)		—			—			—			—			(46	)
Equity in Earnings of Unconsolidated Affiliates (21)		0.03			26			—			—			—			—			26
Income Taxes (22)		—			(3	)		(14	)		(6	)		2			18			(3	)
Interest Expense, Net (23)		(0.11	)		(61	)		9			5			(43	)		(1	)		(91	)
Other (24)		(0.06	)		(6	)		1			26			(67	)		(2	)		(48	)
Share Differential (25)		(0.59	)		—			—			—			—			—			—
2012 Adjusted (non-GAAP) Operating Earnings (Loss)		2.21			1,265			219			305			28			(34	)		1,783
2012 Adjusted (non-GAAP) Operating Earnings (Loss)
Adjustments:
Mark-to-Market Impact of Economic Hedging Activities		0.23			167			—			—			—			18			185
Unrealized Gains Related to NDT Fund Investments (1)		0.07			54			—			—			—			—			54
Plant Retirements and Divestitures (2)		(0.25	)		(200	)		—			—			—			—			(200	)
Asset Retirement Obligation (3)		(0.01	)		(6	)		—			—			—			—			(6	)
Constellation Merger and Integration Costs (6)		(0.26	)		(133	)		—			(8	)		(2	)		(68	)		(211	)
Maryland Commitments (26)		(0.28	)		(22	)		—			—			(83	)		(122	)		(227	)
Amortization of Commodity Contract Intangibles (27)		(0.68	)		(545	)		—			—			—			—			(545	)
FERC Settlement (28)		(0.22	)		(172	)		—			—			—			—			(172	)
Reassessment of State Deferred Income Taxes (29)		0.15			13			—			—			—			104			117
Amortization of the Fair Value of Certain Debt (30)		0.01			7			—			—			—			—			7
Other Acquisition Costs		—			(3	)		—			—			—			—			(3	)
2012 GAAP Earnings (Loss)	$	0.97		$	425		$	219		$	297		$	(57	)	$	(102	)	$	782

(a) For the nine months ended September 30, 2012, includes financial results for Constellation and BGE beginning on March 12, 2012, the date the merger was completed. Therefore, the results of operations from 2012 and 2011 are not comparable for Generation, BGE, Other and Exelon. The explanations below identify any significant or unusual items affecting the results of operations.

(b) Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

(c) As approved by the Maryland PSC, BGE records a monthly adjustment to residential and the majority of its commercial and industrial customers to eliminate the effect of abnormal weather and usage patterns per customer on distribution volumes.

(1) Reflects the impact of unrealized losses in 2011 and unrealized gains in 2012 on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2) For 2012, primarily reflects the impact associated with the expected sale in the fourth quarter of 2012 of three generating stations associated with certain of the regulatory approvals required for the merger. For 2012 and 2011, also reflects incremental accelerated depreciation associated with the retirement of certain fossil generating units and compensation for operating two of the units past their planned retirement date under a FERC-approved reliability-must-run rate schedule.

(3) Primarily reflects an increase in Generation’s decommissioning obligation for spent nuclear fuel at retired nuclear units.

(4) Reflects the impact of a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

(5) Reflects one-time benefits pursuant to the ComEd 2011 electric distribution rate case order for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

(6) Reflects certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(7) Primarily reflects a non-cash bargain purchase gain (negative goodwill) in 2011 in connection with the acquisition of Wolf Hollow, net of acquisition costs.

(8) Primarily reflects the impact of higher nuclear fuel prices, excluding CENG.

(9) Primarily reflects the impact of decreased capacity prices related to the RPM for the PJM market, partially offset by the addition of Constellation’s financial results in 2012.

(10) Primarily reflects the addition of Constellation’s financial results in 2012, partially offset by the impact of decreased realized market prices for the sale of energy in the Mid-Atlantic and Midwest regions.

(11) Reflects intercompany expense in 2011 at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

(12) Reflects the impacts on distribution revenues recorded prior to December 31, 2011, pursuant to the final order issued by the ICC on the 2011 performance based formula rate proceeding under EIMA.

(13) For ComEd, primarily reflects increased distribution revenue through June 2012 pursuant to the 2011 electric distribution rate case order, increased transmission revenue and increased cost recovery for energy efficiency and demand response programs (completely offset in operating and maintenance expense).

(14) Primarily reflects one-time net benefits pursuant to the 2011 ComEd electric distribution rate case order to reestablish previously expensed plant balances and to recognize the estimated recovery of funds for working capital related to the procurement of energy.

(15) Primarily reflects the addition of Constellation and BGE’s financial results in 2012 and the impacts of increased wages and other benefits and increased contracting expenses (exclusive of planned nuclear refueling outages and incremental storm costs). At ComEd, primarily reflects increased contracting expenses resulting from new projects related to EIMA. At PECO, primarily reflects a decrease in contracting expenses.

(16) Primarily reflects the impact of decreased planned nuclear refueling outage days in 2012, excluding Salem and CENG.

(17) The increase in pension and OPEB costs primarily reflect the impact of lower actuarially assumed discount rates and expected return on assets for 2012 as compared to 2011.

(18) Primarily reflects the addition of Constellation and BGE’s financial results in 2012, increased costs at ComEd associated with energy efficiency and demand response programs (completely offset by increased other energy delivery revenues at ComEd) and the impact of storm costs in the BGE service territory, partially offset by decreased storm costs in the ComEd and PECO service territories.

(19) Includes increased depreciation expense across the operating companies due to ongoing capital expenditures and the non-cash amortization of intangible assets at Generation primarily related to the trade name and retail relationships recorded at fair value at the merger date.

(20) Reflects one-time interest and tax benefits in 2011 associated with a change in the timing of the deduction for the transfer of cash or investments from nonqualified nuclear decommissioning trust funds to qualified decommissioning trust funds pursuant to the Energy Policy Act of 2005 and related Treasury Regulations.

(21) Primarily reflects equity in earnings in CENG, partially offset by the non-cash amortization of the fair value basis difference recorded at the merger date.

(22) At Generation, primarily reflects a 2012 reduction in manufacturing deduction benefits, offset by an increase in investment tax credits attributable to AVSR. At PECO, primarily reflects a 2011 benefit for the electric transmission and distribution property repairs deduction, partially offset by a 2012 gas property repairs deduction.

(23) Primarily reflects the addition of Constellation and BGE’s financial results in 2012 and the impact of higher interest expense at Generation and BGE due to higher outstanding debt, partially offset by the impact of lower interest expense at ComEd and PECO due to lower outstanding debt.

(24) For Generation, primarily reflects the addition of Constellation’s financial results, partially offset by realized NDT fund gains related to changes to the investment strategy and favorable market conditions in 2012. For PECO, primarily reflects decreased gross receipts tax (completely offset by decreased PECO margins) and reduced sales and use tax.

(25) Reflects the impact on earnings per share due to the increase in Exelon’s average diluted common shares outstanding as a result of the merger.

(26) Reflects costs incurred as part of the Maryland order approving the merger transaction.

(27) Represents the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date.

(28) Reflects costs incurred as part of a March 2012 settlement with the FERC to resolve a dispute related to Constellation’s prior period hedging and risk management transactions.

(29) Primarily reflects a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s deferred taxes as a result of the merger.

(30) Represents the non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in 2013.

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended September 30, 2012									Three Months Ended September 30, 2011
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	4,017		$	480	(c),(d),(e)	$	4,497		$	2,821		$	(33	)(c),(j)	$	2,788
Operating expenses
Purchased power and fuel		2,122			278	(c),(d),(e)		2,400			1,071			(93	)(c),(d)		978
Operating and maintenance		1,415			(373	)(c),(e),(f),(g)		1,042			790			(55	(c),(f),(g),  )(j),(k)		735
Depreciation, amortization, accretion and depletion		207			(13	)(c),(f)		194			139			(19	)(c)		120
Taxes other than income		109			(4	)(c)		105			67			—			67
Total operating expenses		3,853			(112	)		3,741			2,067			(167	)		1,900
Equity in earnings of unconsolidated affiliates		10			50	(e)		60			—			—			—
Operating income		174			642			816			754			134			888
Other income and deductions
Interest expense		(85	)		(5	)(h)		(90	)		(37	)		—			(37	)
Other, net		83			(60	)(c),(f),(i)		23			(164	)		181	(i),(j)		17
Total other income and deductions		(2	)		(65	)		(67	)		(201	)		181			(20	)
Income before income taxes		172			577			749			553			315			868
Income taxes		85			210	(c),(d),(e),  (f),(g),(h),(i)		295			167			179	(c),(d),(f),  (g),(i),(j),  (k)		346
Net income		87			367			454			386			136			522
Net loss attributable to noncontrolling interests		(4	)		—			(4	)		—			—			—
Net income on common stock	$	91		$	367		$	458		$	386		$	136		$	522
	Nine Months Ended September 30, 2012 (a)									Nine Months Ended September 30, 2011
	GAAP (b)			Adjustments			Adjusted Non-GAAP			GAAP (b)			Adjustments			Adjusted Non-GAAP
Operating revenues	$	10,509		$	942	(c),(d),(e)	$	11,451		$	7,919		$	(42	)(c),(j)	$	7,877
Operating expenses
Purchased power and fuel		5,018			540	(c),(d),(e),(f)		5,558			2,795			(366	)(c),(d)		2,429
Operating and maintenance		3,756			(778	(c),(e),(f),  )(g),(k),(l),(m)		2,978			2,306			(61	(c),(f),(g),  )(j),(k)		2,245
Depreciation, amortization, accretion and depletion		564			(43	)(c),(f)		521			416			(65	)(c)		351
Taxes other than income		272			(8	)(c)		264			199			—			199
Total operating expenses		9,610			(289	)		9,321			5,716			(492	)		5,224
Equity in earnings (losses) of unconsolidated affiliates		(69	)		110	(e),(f)		41			—			—			—
Operating income		830			1,341			2,171			2,203			450			2,653
Other income and deductions
Interest expense		(223	)		(11	)(h)		(234	)		(128	)		—			(128	)
Other, net		185			(73	)(c),(f),(i)		112			(12	)		94	(i),(j)		82
Total other income and deductions		(38	)		(84	)		(122	)		(140	)		94			(46	)
Income before income taxes		792			1,257			2,049			2,063			544			2,607
Income taxes		373			417	(c),(d),(e),(f),  (g),(h),(i),(k),  (l),(m),(n)		790			738			226	(c),(d),(f),  (g),(i),(j),  (k),(o)		964
Net income		419			840			1,259			1,325			318			1,643
Net income attributable to noncontrolling interests		(6	)		—			(6	)		—			—			—
Net income on common stock	$	425		$	840		$	1,265		$	1,325		$	318		$	1,643

(a) Includes financial results for Constellation beginning on March 12, 2012, the date the merger was completed.

(b) Results reported in accordance with GAAP.

(c) Adjustment to exclude costs associated with the retirement of fossil generating units, the impacts of the FERC approved reliability-must-run rate schedule and the impact associated with the expected sale in the fourth quarter of 2012 of three generating stations associated with certain of the regulatory approvals required for the merger.

(d) Adjustment to exclude the mark-to-market impact of Generation's economic hedging activities.

(e) Adjustment to exclude the non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the merger date.

(f) Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(g) Adjustment to exclude the increase in Generation's decommissioning obligation for spent nuclear fuel at retired nuclear units.

(h) Adjustment to exclude the non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in 2013.

(i) Adjustment to exclude the unrealized gains in 2012 and losses in 2011 associated with Generation’s NDT fund investments and the associated contractual accounting relating to income taxes.

(j) Adjustment to exclude the non-cash bargain purchase gain (negative goodwill) associated with the acquisition of Wolf Hollow, net of acquisition costs.

(k) Adjustment to exclude certain costs associated with various acquisitions.

(l) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.

(m) Adjustment to exclude costs associated with the March 2012 settlement with the FERC.

(n) Adjustment to exclude a one-time, non-cash benefit associated with a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s deferred taxes as a result of the merger.

(o) Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

12

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	ComEd
	Three Months Ended September 30, 2012								Three Months Ended September 30, 2011
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,484		$	—	$	1,484		$	1,784		$	—		$	1,784
Operating expenses
Purchased power		678			—		678			932			—			932
Operating and maintenance		350			—		350			396			(1	)(b)		395
Depreciation and amortization		157			—		157			135			—			135
Taxes other than income		81			—		81			78			—			78
Total operating expenses		1,266			—		1,266			1,541			(1	)		1,540
Operating income		218			—		218			243			1			244
Other income and deductions
Interest expense		(74	)		—		(74	)		(86	)		—			(86	)
Other, net		5			—		5			16			—			16
Total other income and deductions		(69	)		—		(69	)		(70	)		—			(70	)
Income before income taxes		149			—		149			173			1			174
Income taxes		59			—		59			61			—	(b)		61
Net income	$	90		$	—	$	90		$	112		$	1		$	113
	Nine Months Ended September 30, 2012								Nine Months Ended September 30, 2011
	GAAP (a)			Adjustments		Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	4,154		$	—	$	4,154		$	4,694		$	—		$	4,694
Operating expenses
Purchased power		1,886			—		1,886			2,436			—			2,436
Operating and maintenance		1,000			—		1,000			930			12	(b),(c)		942
Depreciation and amortization		458			—		458			405			—			405
Taxes other than income		224			—		224			226			—			226
Total operating expenses		3,568			—		3,568			3,997			12			4,009
Operating income		586			—		586			697			(12	)		685
Other income and deductions
Interest expense		(230	)		—		(230	)		(257	)		—			(257	)
Other, net		12			—		12			24			—			24
Total other income and deductions		(218	)		—		(218	)		(233	)		—			(233	)
Income before income taxes		368			—		368			464			(12	)		452
Income taxes		149			—		149			169			—	(b),(c),(d)		169
Net income	$	219		$	—	$	219		$	295		$	(12	)	$	283

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(c) Adjustment to exclude one-time benefits for the recovery of previously incurred costs related to the 2009 restructuring plan and for the passage of Federal health care legislation in 2010.

(d) Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

13

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended September 30, 2012									Three Months Ended September 30, 2011
	GAAP (a)			Adjustments			Adjusted Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	806		$	—		$	806		$	946		$	—		$	946
Operating expenses
Purchased power and fuel		326			—			326			464			—			464
Operating and maintenance		199			(3	)(b)		196			219			2	(b), (c)		221
Depreciation and amortization		55			—			55			51			—			51
Taxes other than income		48			—			48			59			—			59
Total operating expenses		628			(3	)		625			793			2			795
Operating income		178			3			181			153			(2	)		151
Other income and deductions
Interest expense		(32	)		—			(32	)		(34	)		—			(34	)
Other, net		2			—			2			3			—			3
Total other income and deductions		(30	)		—			(30	)		(31	)		—			(31	)
Income before income taxes		148			3			151			122			(2	)		120
Income taxes		25			1	(b)		26			17			(1	)(b), (c)		16
Net income		123			2			125			105			(1	)		104
Preferred security dividends		1			—			1			1			—			1
Net income on common stock	$	122		$	2		$	124		$	104		$	(1	)	$	103
	Nine Months Ended September 30, 2012									Nine Months Ended September 30, 2011
	GAAP (a)			Adjustments			Adjusted  Non- GAAP			GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	2,396		$	—		$	2,396		$	2,942		$	—		$	2,942
Operating expenses
Purchased power and fuel		1,033			—			1,033			1,506			—			1,506
Operating and maintenance		574			(13	)(b)		561			597			2	(b), (c)		599
Depreciation and amortization		161			—			161			150			—			150
Taxes other than income		122			—			122			165			—			165
Total operating expenses		1,890			(13	)		1,877			2,418			2			2,420
Operating income		506			13			519			524			(2	)		522
Other income and deductions
Interest expense		(94	)		—			(94	)		(102	)		—			(102	)
Other, net		6			—			6			11			—			11
Total other income and deductions		(88	)		—			(88	)		(91	)		—			(91	)
Income before income taxes		418			13			431			433			(2	)		431
Income taxes		118			5	(b)		123			119			(1	)(b), (c)		118
Net income		300			8			308			314			(1	)		313
Preferred security dividends		3			—			3			3			—			3
Net income on common stock	$	297		$	8		$	305		$	311		$	(1	)	$	310

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives

(c) Adjustment to exclude a decrease in PECO's asset retirement obligation.

14

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	BGE
	Three Months Ended September 30, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	720		$	—		$	720
Operating expenses
Purchased power and fuel		373			—			373
Operating and maintenance		201			(1	)(b)		200
Depreciation and amortization		68			—			68
Taxes other than income		48			—			48
Total operating expenses		690			(1	)		689
Operating income		30			1			31
Other income and deductions
Interest expense		(35	)		—			(35	)
Other, net		5			—			5
Total other income and deductions		(30	)		—			(30	)
Income before income taxes		—			1			1
Income taxes		—			—	(b)		—
Net income		—			1			1
Preference stock dividends		4			—			4
Net loss on common stock	$	(4	)	$	1		$	(3	)
	March 12, 2012 through September 30, 2012
	GAAP (a)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	1,388		$	113	(c)	$	1,501
Operating expenses
Purchased power and fuel		727			—			727
Operating and maintenance		423			(33	)(b),(c)		390
Depreciation and amortization		157			—			157
Taxes other than income		104			2	(c)		106
Total operating expenses		1,411			(31	)		1,380
Operating income (loss)		(23	)		144			121
Other income and deductions
Interest expense		(77	)		—			(77	)
Other, net		14			—			14
Total other income and deductions		(63	)		—			(63	)
Income (loss) before income taxes		(86	)		144			58
Income taxes		(37	)		59	(b),(c)		22
Net income (loss)		(49	)		85			36
Preference stock dividends		8			—			8
Net income (loss) on common stock	$	(57	)	$	85		$	28

(a) Results reported in accordance with GAAP.

(b) Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives

(c) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.

15

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating Earnings to

GAAP Consolidated Statements of Operations

(unaudited)

(in millions)

	Other (a)
	Three Months Ended September 30, 2012 (b)									Three Months Ended September 30, 2011
	GAAP (c)			Adjustments			Adjusted Non- GAAP			GAAP (c)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(462	)	$	(16	)(d)	$	(478	)	$	(297	)	$	—		$	(297	)
Operating expenses
Purchased power and fuel		(473	)		—			(473	)		(346	)		—			(346	)
Operating and maintenance		(9	)		(1	)(e)		(10	)		8			(11	)(e)		(3	)
Depreciation and amortization		13			—			13			7			—			7
Taxes other than income		4			—			4			3			—			3
Total operating expenses		(465	)		(1	)		(466	)		(328	)		(11	)		(339	)
Operating income (loss)		3			(15	)		(12	)		31			11			42
Other income and deductions
Interest expense		(20	)		3	(e)		(17	)		(25	)		—			(25	)
Other, net		6			—			6			3			—			3
Total other income and deductions		(14	)		3			(11	)		(22	)		—			(22	)
Income (loss) before income taxes		(11	)		(12	)		(23	)		9			11			20
Income taxes		(8	)		(4	)(d),(e)		(12	)		10			5	(e)		15
Net income (loss)	$	(3	)	$	(8	)	$	(11	)	$	(1	)	$	6		$	5
	Nine Months Ended September 30, 2012 (b)									Nine Months Ended September 30, 2011
	GAAP (c)			Adjustments			Adjusted Non- GAAP			GAAP (c)			Adjustments			Adjusted Non- GAAP
Operating revenues	$	(1,242	)	$	(31	)(d)	$	(1,273	)	$	(850	)	$	—		$	(850	)
Operating expenses
Purchased power and fuel		(1,266	)		—			(1,266	)		(901	)		—			(901	)
Operating and maintenance		196			(227	)(e),(f)		(31	)		30			(35	)(e)		(5	)
Depreciation and amortization		36			—			36			16			—			16
Taxes other than income		15			—			15			12			—			12
Total operating expenses		(1,019	)		(227	)		(1,246	)		(843	)		(35	)		(878	)
Operating income (loss)		(223	)		196			(27	)		(7	)		35			28
Other income and deductions
Interest expense		(73	)		3	(e)		(70	)		(58	)		—			(58	)
Other, net		36			—			36			31			—			31
Total other income and deductions		(37	)		3			(34	)		(27	)		—			(27	)
Income (loss) before income taxes		(260	)		199			(61	)		(34	)		35			1
Income taxes		(158	)		131	(d),(e),  (f),(g)		(27	)		8			10	(e),(h)		18
Net loss	$	(102	)	$	68		$	(34	)	$	(42	)	$	25		$	(17	)

(a) Other primarily includes eliminating and consolidating adjustments, Exelon's corporate operations, shared service entities and other financing and investment activities.

(b) Includes financial results for Constellation and BGE, beginning on March 12, 2012, the date the merger was completed.

(c) Results reported in accordance with GAAP.

(d) Adjustment to exclude the mark-to-market impact of Exelon's economic hedging activities.

(e) Adjustment to exclude certain costs incurred associated with the merger, including transaction costs, employee-related expenses (e.g. severance, retirement, relocation and retention bonuses) and integration initiatives.

(f) Adjustment to exclude costs incurred as part of the Maryland order approving the merger transaction.

(g) Adjustment to exclude a one-time, non-cash benefit associated with a change in state deferred tax rates resulting from a reassessment of anticipated apportionment of Exelon’s deferred taxes as a result of the merger.

(h) Adjustment to exclude a one-time, non-cash charge to remeasure deferred taxes at higher corporate tax rates pursuant to the Illinois tax rate change legislation.

16

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended
	Sep. 30, 2012 (a)		Jun. 30, 2012 (a)		Mar. 31, 2012		Dec. 31, 2011			Sep. 30, 2011
Supply (in GWhs)
Nuclear Generation (b)
Mid-Atlantic		11,449		12,277		12,064		11,587			12,158
Midwest		23,132		22,860		23,198		23,306			23,887
Total Nuclear Generation		34,581		35,137		35,262		34,893			36,045
Fossil and Renewables (b)
Mid-Atlantic (b)(d)		2,547		2,316		1,791		1,637			1,722
Midwest		171		228		272		188			88
New England		3,953		2,755		889		—			2
New York		—		—		—		—			—
ERCOT (e)		2,410		2,177		840		457			1,214
Other (f)		1,813		1,923		819		394			249
Total Fossil and Renewables		10,894		9,399		4,611		2,676			3,275
Purchased Power
Mid-Atlantic (c)		6,811		7,111		2,577		739			702
Midwest		3,035		1,558		2,552		1,143			1,756
New England		1,961		3,905		1,100		—			—
New York (c)		4,026		2,818		935		—			—
ERCOT (e)		7,741		6,686		2,832		1,150			2,928
Other (f)		5,372		6,012		1,769		482			887
Total Purchased Power		28,946		28,090		11,765		3,514			6,273
Total Supply/Sales by Region (h)
Mid-Atlantic (g)		20,807		21,704		16,432		13,963			14,582
Midwest (g)		26,338		24,646		26,022		24,637			25,731
New England		5,914		6,660		1,989		—			2
New York		4,026		2,818		935		—			—
ERCOT		10,151		8,863		3,672		1,607			4,142
Other (f)		7,185		7,935		2,588		876			1,136
Total Supply/Sales by Region		74,421		72,626		51,638		41,083			45,593
	Three Months Ended
	Sep. 30, 2012 (a)		Jun. 30, 2012 (a)		Mar. 31, 2012		Dec. 31, 2011			Sep. 30, 2011
Average Margin ($/MWh) (i) (j)
Mid-Atlantic (k)	$	43.64	$	40.68	$	46.86	$	56.08		$	57.19
Midwest (k)		27.68		31.00		31.40		34.18			33.15
New England		13.70		9.01		19.61		n.m.			n.m.
New York		3.23		13.84		8.56		n.m.			n.m.
ERCOT		15.66		13.43		9.26		(6.02	)		24.85
Other (f)		5.85		4.28		5.41		(4.13	)		(4.85	)
Average Margin - Overall Portfolio	$	25.96	$	26.15	$	32.57	$	39.31		$	39.19
Around-the-clock Market Prices ($/MWh) (l)
PJM West Hub	$	38.13	$	30.40	$	31.10	$	35.07		$	46.17
NiHub		34.29		26.02		27.13		25.97			37.30
New England Mass Hub ATC Spark Spread		12.69		7.77		0.80		6.70			13.30
NYPP Zone A		34.56		27.87		27.18		32.03			40.89
ERCOT North Spark Spread		3.60		6.01		3.46		1.11			36.70
	Three Months Ended
	Sep. 30, 2012 (a)		Jun. 30, 2012 (a)		Mar. 31, 2012		Dec. 31, 2011			Sep. 30, 2011
Outage Days (m)
Refueling		43		51		67		103			33
Non-refueling		40		16		16		11			3
Total Outage Days		83		67		83		114			36

(a) Includes results for Constellation beginning on March 12, 2012, the date the merger was completed.

(b) Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and does not include ownership through equity method investments (e.g. CENG).

(c) Purchased power includes physical volumes of 3,126 GWhs, 3,225 GWhs and 319 GWhs in the Mid-Atlantic and 2,997 GWhs, 2,817 GWhs and 722 GWhs in New York as a result of the PPA with CENG for the three months ended September 30, 2012, June 30, 2012 and March 31, 2012, respectively.

(d) Excludes generation under the reliability-must-run rate schedule and generation of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities planned for divestiture as a result of the Exelon and Constellation merger.

(e) Generation from Wolf Hollow is included in purchased power for the period ending June 30, 2011 and through the acquisition date of August 24, 2011, and included within Fossil and Renewables subsequent to the acquisition date.

(f) Other Regions includes South, West and Canada, which are not considered individually significant.

(g) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.

(h) Total sales do not include physical proprietary trading volumes of 4,352 GWhs, 3,873 GWhs, 1,757 GWhs, 1,235 GWhs and 1,679 GWhs for the three months ended September 30, 2012, June 30, 2012, March 31, 2012, December 31, 2011, and September 30, 2011, respectively.

(i) Excludes Generation’s other business activities not allocated to a region, including retail and wholesale gas, upstream natural gas, proprietary trading, energy efficiency, energy management and demand response, and the design, construction and operation of renewable energy facilities. Also excludes Generation’s compensation under the reliability-must-run rate schedule, the financial results of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities planned for divestiture as a result of the merger, amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the Exelon and Constellation merger and other miscellaneous revenues not allocated to a region.

(j) Excludes the mark-to-market impact of Generation’s economic hedging activities.

(k) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd and settlements of the ComEd swap in the Midwest region.

(l) Represents the average for the quarter.

(m) Outage days exclude Salem and CENG.

17

EXELON CORPORATION

Exelon Generation Statistics

Nine Months Ended September 30, 2012 and 2011

	September 30, 2012 (a)		September 30, 2011
Supply (in GWhs)
Nuclear Generation (b)
Mid-Atlantic		35,790		35,700
Midwest		69,190		68,704
Total Nuclear Generation		104,980		104,404
Fossil and Renewables (b)
Mid-Atlantic (b)(d)		6,654		5,936
Midwest		671		408
New England		7,597		8
ERCOT (e)		5,427		1,572
Other (f)		4,555		1,037
Total Fossil and Renewables		24,904		8,961
Purchased Power
Mid-Atlantic (c)		16,498		2,159
Midwest		7,145		4,827
New England		6,966		—
New York (c)		7,779		—
ERCOT (e)		17,259		6,387
Other (f)		13,153		2,021
Total Purchased Power		68,800		15,394
Total Supply/Sales by Region (h)
Mid-Atlantic(g)		58,942		43,795
Midwest (g)		77,006		73,939
New England		14,563		8
New York		7,779		—
ERCOT		22,686		7,959
Other (f)		17,708		3,058
Total Supply/Sales by Region		198,684		128,759
	September 30, 2012 (a)		September 30, 2011
Average Margin ($/MWh) (i) (j)
Mid-Atlantic (k)	$	43.48	$	58.61
Midwest (k)		30.00		36.57
New England		12.22		n.m.
New York		7.71		n.m.
ERCOT		13.75		11.81
Other (f)		5.08		(3.27	)
Average Margin - Overall Portfolio	$	27.75	$	41.62
Around-the-clock Market Prices ($/MWh) (l)
PJM West Hub	$	33.23	$	46.42
NiHub		29.16		35.46
NEPOOL Mass Hub		7.04		9.41
NYPP Zone A		29.79		38.65
ERCOT North Spark Spread		4.39		15.48

(a) Includes results for Constellation beginning on March 12, 2012, the date the merger was completed.

(b) Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and does not include ownership through equity method investments (e.g. CENG).

(c) Purchased power includes physical volumes of 6,670 GWhs in the Mid-Atlantic and 6,536 GWhs in New York as a result of the PPA with CENG for the nine months ended September 30, 2012.

(d) Excludes generation under the reliability-must-run rate schedule and generation of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities planned for divestiture as a result of the Exelon and Constellation merger.

(e) Generation from Wolf Hollow is included in purchased power for the period ending June 30, 2011 and through the acquisition date of August 24, 2011, and included within Fossil and Renewables subsequent to the acquisition date.

(f) Other Regions includes South, West and Canada, which are not considered individually significant.

(g) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.

(h) Total sales do not include physical proprietary trading volumes of 9,981 GWhs and 4,508 GWhs for the nine months ended September 30, 2012 and 2011, respectively.

(i) Excludes Generation's other business activities not allocated to a region, including retail and wholesale gas, upstream natural gas, proprietary trading, energy efficiency, energy management and demand response, and the design, construction and operation of renewable energy facilities. Also excludes Generation’s compensation under the reliability-must-run rate schedule, the financial results of Brandon Shores, H.A. Wagner, and C.P. Crane, the generating facilities planned for divestiture as a result of the merger, amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the Exelon and Constellation merger and other miscellaneous revenues not allocated to a region.

(j) Excludes the mark-to-market impact of Generation's economic hedging activities.

(k) Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd and settlements of the ComEd swap in the Midwest region.

(l) Represents the average for the quarter.

18

EXELON CORPORATION

ComEd Statistics

	Three Months Ended September 30, 2012 and 2011
	Electric Deliveries (in GWhs)										Revenue (in millions)
								Weather- Normal
	2012		2011		% Change			% Change			2012			2011		% Change
Retail Deliveries and Sales (a)
Residential		9,265		8,876		4.4	%		1.4	%	$	876		$	1,111		(21.2	)%
Small Commercial & Industrial		8,939		8,812		1.4	%		(0.1	)%		344			410		(16.1	)%
Large Commercial & Industrial		7,506		7,494		0.2	%		(0.8	)%		102			102		0.0	%
Public Authorities & Electric Railroads		314		303		3.6	%		3.3	%		11			12		(8.3	)%
Total Retail		26,024		25,485		2.1	%		0.2	%		1,333			1,635		(18.5	)%
Other Revenue (b)												151			149		1.3	%
Total Electric Revenue											$	1,484		$	1,784		(16.8	)%
Purchased Power											$	678		$	932		(27.3	)%
								% Change
Heating and Cooling Degree-Days	2012		2011		Normal			From 2011			From Normal
Heating Degree-Days		107		147		119			(27.2	)%		(10.1	)%
Cooling Degree-Days		859		785		613			9.4	%		40.1	%

	Nine Months Ended September 30, 2012 and 2011
	Electric Deliveries (in GWhs)										Revenue (in millions)
								Weather- Normal
	2012		2011		% Change			% Change			2012			2011		% Change
Retail Deliveries and Sales (a)
Residential		22,345		22,107		1.1	%		(0.5	)%	$	2,372		$	2,745		(13.6	)%
Small Commercial & Industrial		24,742		24,648		0.4	%		(0.2	)%		997			1,177		(15.3	)%
Large Commercial & Industrial		21,048		21,011		0.2	%		0.1	%		296			288		2.8	%
Public Authorities & Electric Railroads		932		920		1.3	%		3.4	%		32			38		(15.8	)%
Total Retail		69,067		68,686		0.6	%		(0.1	)%		3,697			4,248		(13.0	)%
Other Revenue (b)												457			446		2.5	%
Total Electric Revenue											$	4,154		$	4,694		(11.5	)%
Purchased Power											$	1,886		$	2,436		(22.6	)%
								% Change
Heating and Cooling Degree-Days	2012		2011		Normal			From 2011			From Normal
Heating Degree-Days		3,035		4,302		4,048			(29.5	)%		(25.0	)%
Cooling Degree-Days		1,321		1,022		831			29.3	%		59.0	%
Number of Electric Customers	2012		2011
Residential		3,450,364		3,439,704
Small Commercial & Industrial		365,245		364,917
Large Commercial & Industrial		1,986		2,041
Public Authorities & Electric Railroads		4,795		4,801
Total		3,822,390		3,811,463

(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed delivery charges. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy and transmission.

(b) Other revenue primarily includes transmission revenue from PJM. Other items include late payment charges and mutual assistance program revenues.

19

EXELON CORPORATION

PECO Statistics

	Three Months Ended September 30, 2012 and 2011 Electric and Gas Deliveries										Revenue (in millions)
								Weather- Normal
	2012		2011		% Change			% Change			2012			2011		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		4,059		4,085		(0.6	)%		(3.6	)%	$	497		$	598		(16.9	)%
Small Commercial & Industrial		2,245		2,272		(1.2	)%		(1.7	)%		120			138		(13.0	)%
Large Commercial & Industrial		4,165		4,370		(4.7	)%		(4.8	)%		66			85		(22.4	)%
Public Authorities & Electric Railroads		240		239		0.4	%		0.4	%		8			9		(11.1	)%
Total Retail		10,709		10,966		(2.3	)%		(3.6	)%		691			830		(16.7	)%
Other Revenue (b)												61			61		0.0	%
Total Electric Revenue												752			891		(15.6	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		3,646		3,687		(1.1	)%		(3.0	)%		49			51		(3.9	)%
Transportation and Other		5,796		6,190		(6.4	)%		(5.3	)%		5			4		25.0	%
Total Gas		9,442		9,877		(4.4	)%		(4.4	)%		54			55		(1.8	)%
Total Electric and Gas Revenues											$	806		$	946		(14.8	)%
Purchased Power and Fuel											$	326		$	464		(29.7	)%
								% Change
Heating and Cooling Degree-Days	2012		2011		Normal			From 2011			From Normal
Heating Degree-Days		14		18		35			(22.2	)%		(60.0	)%
Cooling Degree-Days		1,138		1,109		934			2.6	%		21.8	%

	Nine Months Ended September 30, 2012 and 2011 Electric and Gas Deliveries										Revenue (in millions)
								Weather- Normal
	2012		2011		% Change			% Change			2012			2011		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		10,154		10,750		(5.5	)%		(2.4	)%	$	1,297		$	1,542		(15.9	)%
Small Commercial & Industrial		6,155		6,437		(4.4	)%		(2.8	)%		357			472		(24.4	)%
Large Commercial & Industrial		11,545		12,012		(3.9	)%		(3.9	)%		179			261		(31.4	)%
Public Authorities & Electric Railroads		714		710		0.6	%		0.6	%		24			29		(17.2	)%
Total Retail		28,568		29,909		(4.5	)%		(3.0	)%		1,857			2,304		(19.4	)%
Other Revenue (b)												171			183		(6.6	)%
Total Electric Revenue												2,028			2,487		(18.5	)%
Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)		32,301		38,982		(17.1	)%		0.5	%		344			429		(19.8	)%
Transportation and Other		19,397		21,428		(9.5	)%		(8.2	)%		24			26		(7.7	)%
Total Gas		51,698		60,410		(14.4	)%		(2.5	)%		368			455		(19.1	)%
Total Electric and Gas Revenues											$	2,396		$	2,942		(18.6	)%
Purchased Power and Fuel											$	1,033		$	1,506		(31.4	)%
								% Change
Heating and Cooling Degree-Days	2012		2011		Normal			From 2011			From Normal
Heating Degree-Days		2,265		2,855		2,974			(20.7	)%		(23.8	)%
Cooling Degree-Days		1,572		1,603		1,282			(1.9	)%		22.6	%

Number of Electric Customers	2012		2011		Number of Gas Customers	2012		2011
Residential		1,416,894		1,412,059	Residential		452,624		448,763
Small Commercial & Industrial		148,829		148,210	Commercial & Industrial		41,338		40,883
Large Commercial & Industrial		3,103		3,116	Total Retail		493,962		489,646
Public Authorities & Electric Railroads		9,666		9,693	Transportation		900		868
Total		1,578,492		1,573,078	Total		494,862		490,514

(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission.

(b) Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c) Reflects delivery volumes and revenues from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas.

20

EXELON CORPORATION

BGE Statistics

Three Months Ended September 30, 2012

	Electric and Gas Deliveries		Revenue (in  millions)
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		3,829	$	400
Small Commercial & Industrial		4,458		166
Large Commercial & Industrial		462		10
Public Authorities & Electric Railroads		47		8
Total Retail		8,796		584
Other Revenue (b)				64
Total Electric Revenue				648
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		11,147		63
Transportation and Other (d)		2,311		9
Total Gas		13,458		72
Total Electric and Gas Revenues			$	720
Purchased Power and Fuel			$	373
Heating and Cooling Degree-Days	2012
Heating Degree-Days		69
Cooling Degree-Days		698

March 12, 2012 through September 30, 2012

	Electric and Gas Deliveries		Revenue (in millions)
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential		7,107	$	682
Small Commercial & Industrial		8,636		327
Large Commercial & Industrial		1,942		41
Public Authorities & Electric Railroads		120		18
Total Retail		17,805		1,068
Other Revenue (b)				138
Total Electric Revenue				1,206
Gas (in mmcfs)
Retail Deliveries and Sales (c)
Retail Sales		31,549		153
Transportation and Other (d)		9,075		29
Total Gas		40,624		182
Total Electric and Gas Revenues			$	1,388
Purchased Power and Fuel			$	727
Heating and Cooling Degree-Days	2012
Heating Degree-Days		2,188
Cooling Degree-Days		987

As of September 30, 2012

Number of Electric Customers	2012		Number of Gas Customers	2012
Residential		1,115,764	Residential		610,353
Small Commercial & Industrial		119,431	Commercial & Industrial		43,978
Large Commercial & Industrial		5,448	Total Retail		654,331
Public Authorities & Electric Railroads		318	Transportation		—
Total		1,240,961	Total		654,331

(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from BGE and customers electing to receive electric generation service from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenue also reflects the cost of energy and transmission.

(b) Other revenue includes wholesale transmission revenue and late payment charges.

(c) Reflects delivery volumes and revenues from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas.

(d) Transportation and other gas revenue includes off-system revenue of 2,311 mmcfs ($8 million) for the three months ended September 30, 2012 and off-system revenue of 9,075 mmcfs ($25 million) from March 12, 2012 through September 30, 2012.

21

EX-99.2

Earnings Conference Call

3

rd

Quarter 2012

November 1

, 2012

Exhibit 99.2

st

Cautionary Statements Regarding

Forward-Looking Information

1

2012 3Q Earnings Release Slides

2012 3Q Earnings Release Slides

This presentation contains certain forward-looking statements within the meaning of the Private Securities

Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual

results to differ materially from the forward-looking statements made by Exelon Corporation, Commonwealth

Edison Company, PECO Energy Company, Baltimore Gas and Electric Company and Exelon Generation

Company, LLC (Registrants) include those factors discussed herein, as well as the items discussed in (1) 

Exelon’s 2011 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s

Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial

Statements and Supplementary Data: Note 18; (2) Constellation Energy Group’s 2011 Annual Report on Form

10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition

and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 12; (3) the

Registrant’s Second Quarter 2012 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A.

Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial

Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note

16; and (4) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to

place undue reliance on these forward-looking statements, which apply only as of the date of this

presentation. None of the Registrants undertakes any obligation to publicly release any revision to its forward-

looking statements to reflect events or circumstances after the date of this presentation.

2012 3Q Earnings Release Slides

2

3Q Update

•

Strong 3Q financial performance

Operating

earnings

of

$0.77/share,

above

$0.65

-

$0.75/share

guidance

range

•

Expect 2012 full year operating earnings of $2.75 -

$2.95/share

Guidance increase driven by year-to-date financial performance and ICC Rehearing

Order

•

Merger is working

Expect

to

achieve

$170M

in

merger

related

O&M

synergies

for

2012

and

$550M

run

rate synergies starting in 2014

Includes additional $50M of O&M reductions starting in 2014

Expect to close Maryland asset divestiture in 4Q 2012

Benefiting from well-matched generation and load footprint

Integrated operations are seamless

Market Fundamentals: Upside in Power Prices

3

Medium & Long Term (2014+)

Market Dynamics

•

Low

gas

prices

and

MATS

(4)

rule

are

major

drivers

of

coal

retirements

•

~42

GW

of

coal

retirements

expected 

(2)

.

Includes

~27

GW

of

retirements in 2014-2016

•

Internal view of $3-6/MWh upside in power prices not currently

reflected in forward prices

•

Over 40% open in 2014, over 75% open in 2015 and mostly open in

2016 and beyond

•

Use of cross-commodity hedges leaves even more upside to heat rate

expansion

Expected upside is the result of plant retirements, higher operating costs for

compliance with environmental standards and a continued disconnect between

heat rates and gas prices

PJM NiHub

ATC Power

(Forecast vs

Market)

(5)

-

1

2

3

4

5

6

7

2013

2014

2015

2016

2017

Retirement/Environmental

Market Discount/Other

PJM West Hub ATC Power (Forecast vs

Market)

(5)

-

1

2

3

4

5

6

7

2013

2014

2015

2016

2017

Retirement/Environmental

Market Discount/Other

(1)

Cross State Air Pollution Rule.

(2)

Retirements estimate is for the Eastern Interconnect as per Exelon’s internal

projections.

(3)

Portfolio hedge percentages are shown as of 9/30/12.

(5)

Mercury and Air Toxics Standards.

(6)

Upside figures are rounded to the nearest $0.50/MWh and are based on 9/30/12

pricing.

         Note: Internal views assume normal weather patterns.

Market Dynamics

•

No

major

impact

on

power

prices

from

CSAPR

(1)

being

vacated

•

~15 GW of retirements expected

(2)

•

Volatile heat rates in 2012 due to volatile gas prices and

weather

•

Fully hedged in 2012 and greater than 85% hedged in 2013

Current & Near Term (2012/2013)

2012 3Q Earnings Release Slides

Portfolio

Portfolio

Impact

(3)

Impact

(3)

4

Exelon Generation: Load Serving Update

2012 3Q Earnings Release Slides

Strategy

•

Serve new customers as existing markets grow

and new markets open

Retail expected to grow at ~11% CAGR for 2011-

2015

Wholesale expected to remain static starting in

2013

•

Improve market share in existing markets

•

Cross sell suite of products to existing

customers  to create higher retention

•

Leverage operational efficiency and national

footprint

2012E

30-40%

60-70%

165

175

2013E

25-35%

185

2015E

2014E

20-30%

170

55-65%

35-45%

2011A

170

90

80

Wholesale Load

Total Contracted

Retail Load

Retail & Wholesale Load (TWh)

(1)

65-75%

70-80%

(1)

(2)

(2)

2012 3Q Earnings Release Slides

+9%

0

50

100

150

200

•

Expected load growth of 1% across the U.S.

•

Switched market expected to grow by

approximately 11% in C&I from 2011 to 2015

•

Switched market expected to grow by

approximately 22% in residential from 2011 to

2015

Retail Landscape

•

Recently, the market has been impacted by

increased competition and aggressive pricing

•

Our disciplined approach to pricing has led to a

reduction in expected volumes and margins

•

Various channels to market are available to

optimize our generation

Execution

Numbers and percentages are rounded to the nearest 5.

Index load expected to be 20% to 30% of total forecasted retail load.

2012 3Q Earnings Release Slides

5

Exelon Generation: Gross Margin Update

September  30, 2012

June 30, 2012

Gross Margin Category ($M)

(1)

2012

(2)

2013

2014

2015

2012

(2)

2013

2014

Open Gross Margin

(2,3,4)

(including South, West, Canada hedged gross margin)

$4,500

$5,750

$6,050

$6,200

$4,450

$5,400

$5,850

Mark-to-Market of Hedges

(4,5)

$3,200

$1,350

$500

$250

$3,100

$1,650

$600

Power New Business / To Go

$50

$500

$750

$950

$100

$550

$850

Non-Power Margins Executed

$300

$150

$100

$50

$250

$100

$100

Non-Power New Business / To Go

$100

$450

$500

$550

$150

$500

$500

Total Gross Margin

$8,150

$8,200

$7,900

$8,000

$8,050

$8,200

$7,900

(1) Gross margin rounded to nearest $50M.

(2)

(3)

Excludes

Maryland

assets

to

be

divested. 

(4) Includes

CENG

Joint

Venture.

(5)

Key Highlights of 3Q 2012

•

We

have

optimized

our

hedging

during

this

volatile

period

and

are

back

on

ratable

•

Expect

to

employ

a

variety

of

strategies

to

leverage

ourselves

for

expected

upside

Position our regional portfolios within our Bull/Bear framework to best take advantage of various market anomalies

Further utilize cross-commodity hedges to protect against further downside in the natural gas market, while remaining

open to our view that heat rates will expand

Our forward view continues to be that there is upside in power prices and our

fleet is leveraged for that upside

September

30 

gross

margins

reflect

our

new

expectations

for

wholesale

and

retail

load

volumes

and

margins

Forward

power

market

prices

experienced

sizeable

swings

through

the

3 

quarter

th

rd

Stub period calculated by excluding Jan 2012 through mid-March 2012 for Constellation only.

Mark to Market of Hedges assumes mid-point of hedge percentages.

Exelon’s Financial Priorities & Actions

6

2012 3Q Earnings Release Slides

Priorities

•

Number one priority is to maintain

investment grade across all

registrants

•

Second priority is return value to our

shareholders through our dividend

•

Third priority is investing in

sustainable growth projects

Actions

•

Significant reduction in capital

expenditures in 2013-2015

•

Deferral of Limerick and LaSalle

uprates to allow for power market

recovery

•

Removed unidentified renewable

capex

•

Further reduction in O&M of $50M

starting in 2014

2012 3Q Earnings Release Slides

Taking action to meet our top priorities through changes in spending plans and 

timing  of  investments to align with a power market recovery

Updating Exelon Generation Growth Capital Spend

7

•

Nuclear uprates capex reduced by $1,025M in 2012-2015

-

Deferred Limerick EPU project completion from 2017 to 2021

-

Deferred LaSalle EPU project completion another two years from 2018 to 2020

•

Eliminated unidentified wind and solar capex of $1,250M in 2013-2015

-

Renewable projects will be pursued in the future if they meet our internal parameters

•

Peach Bottom EPU project to be completed as planned

-

Strong returns (well above 10% IRR on a go forward basis) under range of different pricing scenarios

-

Invested $55M to date, at ownership level

-

At

ownership,

project

is

smallest

of

the

EPUs

with

total

capex

of

$415M

through

2016;

limited

impact

on

balance sheet

•

Maintained Upstream Gas spend

-

Strong returns (>12% IRR)

-

Off-balance sheet financing

2012 3Q Earnings Release Slides

ExGen Growth Capex (June 2012 Analyst Day)

(in $M)

300

100

50

75

100

2015

200

100

2014

275

175

2013

850

575

225

2012

(1)

1,675

625

675

Wind

Solar

Upstream Gas

Nuclear Uprates

(in $M)

ExGen Growth Capex (3Q 2012)

(1)

2012 CapEx includes CEG from merger close date.

EPU = Extended Power Uprate

400

375

475

50

100

100

425

1,125

2014

175

2013

1,225

75

675

2012

(1)

1,775

650

625

Nuclear Uprates

Upstream Gas

Solar

Wind

2012 3Q Earnings Release Slides

2012 3Q Earnings Release Slides

8

ComEd Regulatory Update

•

ICC Rehearing Order (issued 10/3/12) on pension asset, interest rate on cost

reconciliation and average vs. year-end rate base

Reversed

decision

on

pension

asset

by

granting

ComEd

recovery

on

the

cost

of

funding its pension

Upheld the decision to use average rate base (vs. ComEd’s position of using year

end rate base)

Revised the decision on interest on reconciliation balances, granting a rate equal

to the short term debt rate (vs. ComEd’s view of using WACC rate)

•

As a result of the order, ComEd has deferred $450 million of capital

expenditures from 2012-2014 to 2015 and beyond

•

Filed a notice of appeal on 10/4/12 to challenge the interest rate on

reconciliation and average rate base issues plus other items lost in May

2012 order

2012 3Q Earnings Release Slides

9

3Q 2012 Operating Results

•

Delivered non-GAAP operating earnings in 3Q of

$0.77/share

(1)

, above guidance expectations,

primarily due to:

ExGen

•

Portfolio optimization of $0.07/share

•

Lower than expected nuclear volume of

$(0.03)/share

ComEd

•

Favorable weather of $0.01/share

PECO

•

Favorable weather of $0.01/share

•

Higher than expected benefit of $0.02/share from

gas distribution tax repairs deduction

3Q 2012

$0.77

$0.53

$0.10

$0.14

$0.00

HoldCo

ExGen

ComEd

PECO

BGE

2012 3Q Results

(1)

Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

2012 Projected Sources and Uses of Cash

10

($ in Millions)

2012 3Q Earnings Release Slides

(1)

Exelon beginning cash balance as of  12/31/11. Excludes counterparty collateral activity.

(2)

Includes $675 million of Constellation net collateral paid to counterparties prior to merger completion.

(3)

Cash Flow from Operations primarily includes net cash flows provided by operating activities, estimated proceeds from Maryland clean coal fleet divestitures and net cash flows used in

investing activities other than capital expenditures. 

(4)

Dividends are subject to declaration by the Board of Directors.

(5)

Excludes PECO’s $225 million Accounts Receivable (A/R) Agreement with Bank of Tokyo. PECO’s A/R Agreement was extended in accordance with its terms through August 30, 2013.

(6)

“Other”

includes proceeds from options and expected changes in short-term debt.

(7)

Includes cash flow activity from Holding Company, eliminations, and other corporate entities.  Represents Constellation cash flows from merger close through December 31, 2012.

(7)

Beginning Cash Balance

(1)

$550

Cash acquired from Constellation

(2)

150

n/a

n/a

1,375

1,650

Cash Flow from Operations

(3)

250

1,175

900

3,475

5,825

CapEx (excluding other items below):

(425)

(1,225)

(350)

(975)

(3,050)

Nuclear Fuel

n/a

n/a

n/a

(1,150)

(1,150)

Dividend

(4)

(1,725)

Nuclear Uprates

n/a

n/a

n/a

(300)

(300)

Wind

n/a

n/a

n/a

(625)

(625)

Solar

n/a

n/a

n/a

(675)

(675)

Upstream

n/a

n/a

n/a

(75)

(75)

Utility Smart Grid/Smart Meter

(75)

(50)

(75)

n/a

(200)

Net Financing (excluding Dividend):

Debt Issuances

(5)

250

350

350

775

1,725

Debt Retirements

(175)

(450)

(375)

(125)

(1,125)

Project Finance/Federal Financing Bank

Loan

n/a

n/a

n/a

375

375

Other

(6)

25

(25)

(100)

Ending Cash Balance

(1)

$1,100

2012 3Q Earnings Release Slides

11

2012 Earnings Guidance

2012 Prior Guidance

$2.55 -

$2.85

(1)

$0.30 -

$0.40

$0.40

-

$0.50

$0.05

-

$0.15

HoldCo

ExGen

ComEd

PECO

BGE

(1)

2012 Revised Guidance

$2.75 -

$2.95

(1)

$0.45 -

$0.50

$0.40

-

$0.50

$0.05

-

$0.10

HoldCo

ExGen

ComEd

PECO

BGE

+ Impact of ICC Rehearing

Order on ComEd’s earnings

+ Higher than expected RNF

at ExGen in 3Q 2012

$1.75 -

$1.95

$1.85 -

$1.95

Updated

FY

2012

operating

earnings

to

$2.75

-

$2.95/share

2012 guidance includes Constellation Energy and BGE earnings for March 12 – December 31, 2012. Based on expected 2012 average outstanding shares of 819M.  Guidance incorporates

preliminary cost estimates of the impact of Hurricane Sandy. Earnings guidance for OpCos may not add up to consolidated EPS guidance.

Key Drivers of Change

in Full Year Guidance

2012 3Q Earnings Release Slides

12

Wrap Up

•

Strong financial performance in 2012; increasing and tightening our full year

2012 earnings guidance to $2.75 -

$2.95/share

•

Expect $3 –

6/MWh upside to materialize in the forward curves in 2013

•

Right platform to take advantage of a power market recovery

•

Investment grade ratings and dividend are our top priorities

•

Timing our investments to align with a power market recovery

Commitment to protect and create shareholder value

13

APPENDIX

2012 3Q Earnings Release Slides

14

Exelon Generation Disclosures

September 30, 2012

2012 3Q Earnings Release Slides

15

Portfolio Management Strategy

Protect Balance Sheet

Ensure Earnings Stability

Create Value

Align Hedging & Financials

Establishing Minimum Hedge Targets

Capital

Structure

Dividend

Capital &

Operating

Expenditure

Credit Rating

High End of Profit

Low End of Profit

% Hedged

Open Generation

with LT Contracts

Portfolio Management &

Optimization

Portfolio Management Over Time

Exercising Market Views

Purely ratable

Actual hedge %

Market views on timing, product

allocation and regional spreads

reflected in actual hedge %

Strategic Policy Alignment

•Aligns hedging program with

financial policies and financial

outlook

•Establish minimum hedge targets

to meet financial objectives of the

company (dividend, credit rating)

•Hedge enough commodity risk to

meet future cash requirements

under a stress scenario

Three-Year Ratable Hedging

•Ensure stability in near-term cash

flows and earnings

•Disciplined approach to hedging

•Tenor aligns with customer

preferences and market liquidity

•Multiple channels to market that

allow us to maximize margins

•Large open position in outer years

to benefit from price upside

Bull / Bear Program

•Ability to exercise fundamental

market views to create value within

the ratable framework

•Modified timing of hedges versus

purely ratable

•Cross-commodity hedging (heat

rate positions, options, etc.)

•Delivery locations, regional and

zonal spread relationships

2012 3Q Earnings Release Slides

16

Components of Gross Margin Categories

2012 3Q Earnings Release Slides

2012 3Q Earnings Release Slides

Margins move from new business to MtM of hedges over

the course of the year as sales are executed

Margins move from “Non power new business”

to

“Non power executed”

over the course of the year

Open Gross

Margin

MtM of

Hedges

(2)

“Power”

New

Business

“Non Power”

Executed

“Non Power”

New Business

Gross margin linked to power production and sales

Gross margin from

other business activities

•

MtM of power,

capacity and

ancillary hedges,

including cross

commodity, retail

and wholesale

load transactions

•

Provided directly

at a consolidated

level for five major

regions. Provided

indirectly for each

of the five major

regions via EREP,

reference price,

hedge %, expected

generation

•

Generation Gross

Margin at current

market prices,

including capacity

& ancillary

revenues, nuclear fuel

amortization

and fossils fuels

expense

•

Exploration and

Production

•

PPA Costs & Revenues

•

Provided at a

consolidated level for

all regions (includes

hedged gross margin

for South, West &

Canada

(1)

)

•

Retail, Wholesale

planned electric

sales

•

Portfolio

Management new

business

•

Mid marketing

new business

•

Retail, Wholesale 

executed gas sales

•

Load Response

•

Energy Efficiency

•

BGE Home

•

Distributed Solar

•

Retail, Wholesale

planned gas sales

•

Load Response

•

Energy Efficiency

•

BGE Home

•

Distributed Solar

•

Portfolio

Management /

origination fuels

new business

•

Proprietary trading

(3)

(1) Hedged gross margins for South, West & Canada region will be included with Open Gross Margin, and no expected generation, hedge %, EREP or reference prices provided for this region.

(2) MtM of hedges provided directly for the five larger regions. MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh.

(3) Proprietary trading gross margins will remain within “Non Power” New Business category and not move to “Non Power” Executed category.

17

ExGen Disclosures 

Gross Margin Category ($M)

(1,2)

2012

(3)

2013

2014

2015

Open Gross Margin

(including South, West & Canada hedged GM)

(4,5)

$4,500

$5,750

$6,050

$6,200

Mark to Market of Hedges

(5,6)

$3,200

$1,350

$500

$250

Power New Business / To Go

$50

$500

$750

$950

Non-Power Margins Executed

$300

$150

$100

$50

Non-Power New Business / To Go

$100

$450

$500

$550

Total Gross Margin

$8,150

$8,200

$7,900

$8,000

Reference Prices

(7)

2012

2013

2014

2015

Henry Hub Natural Gas ($/MMbtu)

$2.77

$3.84

$4.18

$4.37

Midwest: NiHub ATC prices ($/MWh)

$28.95

$30.59

$31.34

$32.32

Mid-Atlantic: PJM-W ATC prices ($/MWh)

$33.93

$38.24

$39.44

$40.77

ERCOT-N ATC Spark Spread ($/MWh)

HSC Gas, 7.2HR, $2.50 VOM

$3.67

$8.37

$8.30

$7.15

New York: NY Zone A ($/MWh)

$30.85

$35.19

$35.98

$36.55

New England: Mass Hub ATC Spark Spread($/MWh)

ALQN Gas, 7.5HR, $0.50 VOM

$6.72

$4.42

$3.79

$4.07

2012 3Q Earnings Release Slides

2012 3Q Earnings Release Slides

(1)

Gross margin does not include revenue related to decommissioning, Exelon Nuclear Partners

and entities consolidated solely as a result of the application of FIN 46R.

(2)

Gross margin rounded to nearest $50M.

(3)

Stub period calculated by excluding Jan 2012 through mid-March 2012 for Constellation

only.

(4)

Excludes Maryland assets to be divested.

(5)

Includes CENG Joint Venture.

(6)

(7)

Based on September 30, 2012 market conditions.

Mark

to

Market

of

Hedges

assumes

mid

-

point

of

hedge

percentages.

18

ExGen Disclosures

Generation and Hedges

2012

(1)

2013

2014

2015

Exp. Gen (GWh)

(4)

219,500

218,700

211,400

209,800

Midwest

100,700

97,400

97,500

99,000

Mid-Atlantic

(2,3)

71,800

75,000

72,200

71,800

ERCOT

19,900

18,500

16,900

15,800

New York

(3)

13,000

13,800

10,900

9,300

New England

14,100

14,000

13,900

13,900

% of Expected Generation Hedged

(5)

99-102%

88-91%

56-59%

21-24%

Midwest

99-102%

89-92%

56-59%

20-23%

Mid-Atlantic

(2,3)

99-102%

88-91%

57-60%

24-27%

ERCOT

96-99%

78-81%

53-56%

28-31%

New York

(3)

98-101%

92-95%

61-64%

15-18%

New England

97-100%

89-92%

51-54%

11-14%

Effective Realized Energy Price ($/MWh)

(6)

Midwest

$42.00

$38.00

$35.00

$34.50

Mid-Atlantic

(2,3)

$56.00

$48.00

$47.50

$50.50

ERCOT

(7)

$9.00

$7.50

$5.00

$5.00

New York

(3)

$44.00

$36.00

$35.00

$52.00

New England

(7)

$8.00

$7.00

$4.00

$5.00

2012 3Q Earnings Release Slides

2012 3Q Earnings Release Slides

(1) Stub period calculated by excluding Jan 2012 through mid-March 2012 for Constellation only. (2) Excludes Maryland assets to be divested (3) Includes CENG Joint Venture. (4) Expected

generation represents the amount of energy estimated to be generated or purchased through owned or contracted for capacity.  Expected generation is based upon a simulated dispatch model

that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 10

refueling outages in 2012 and 2013 and 11 refueling outages in 2014 and 2015 at Exelon-operated nuclear plants and Salem but excludes CENG.  Expected generation assumes capacity

factors of 92.8%, 93.5%, 93.8%, and 93.3% in 2012, 2013, 2014 and 2015 at Exelon-operated nuclear plants excluding Salem and CENG. These estimates of expected generation in 2012,

2013, 2014 and 2015 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years.  (5) Percent of expected

generation hedged is the amount of equivalent sales divided by expected generation.  Includes all hedging products, such as wholesale and retail sales of power, options and swaps. Uses

expected value on options. (6) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged.  It is developed by

considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs and RPM

capacity revenue, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations.  It can be compared with the reference

prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges. (7) Spark spreads shown for ERCOT and New England.

19

ExGen Hedged Gross Margin Sensitivities

Gross Margin Sensitivities (With Existing Hedges) 

(1, 4)

2012

2013

2014

2015

Henry Hub Natural Gas ($/MMbtu)

(2)

+ $1/MMbtu

$(5)

$55

$400

$780

-

$1/MMbtu

$25

$(15)

$(325)

$(700)

NiHub ATC Energy Price

+ $5/MWh

$(5)

$40

$230

$390

-

$5/MWh

$5

$(35)

$(230)

$(385)

PJM-W ATC Energy Price

(2)

+ $5/MWh

$(5)

$50

$165

$295

-

$5/MWh

$5

$(40)

$(160)

$(285)

NYPP Zone A ATC Energy Price

+ $5/MWh

$5

$15

$35

$45

-

$5/MWh

$(5)

$(15)

$(35)

$(45)

Nuclear Capacity Factor

(3)

+/-

1%

+/-

$10

+/-

$40

+/-

$45

+/-

$45

2012 3Q Earnings Release Slides

2012 3Q Earnings Release Slides

(1) Based on September 30, 2012 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an internal model

that is updated periodically. Power prices sensitivities are derived by adjusting the power price assumption while keeping all other prices inputs constant. Due to correlation of the

various assumptions, the hedged gross margin impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin impact calculated when

correlations between the various assumptions are also considered. (2) Excludes Maryland assets to be divested. (3) Includes CENG Joint Venture (4) Sensitivities based on

commodity exposure which includes open generation and all committed transactions.

20

Exelon Generation Hedged Gross Margin Upside/Risk

2012 3Q Earnings Release Slides

2012 3Q Earnings Release Slides

(1) Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged

supply is sold into the spot market.  Approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future

transactions and potential modeling changes. These ranges of approximate gross margin in 2013 and 2014 do not represent earnings guidance or a forecast of future results as

Exelon has not completed its planning or optimization processes for those years. The price distributions that generate this range are calibrated to market quotes for power, fuel, load

following products, and options as of September 30, 2012 (2) Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed

transactions. (3) Excludes Maryland assets to be divested.

$8,200

$8,100

$8,500

$7,850

$8,950

$7,150

21

Illustrative Example of Modeling Exelon Generation             

2013 Gross Margin

Row

Item

Midwest

Mid-

Atlantic

ERCOT

New

England

New York

South,

West &

Canada

(A)

Start with fleet-wide open gross margin 

$5.75 billion

(B)

Expected Generation (TWh)

97.4

75.0

18.5

14.0

13.8

(C)

Hedge % (assuming mid-point of range)

90.5%

89.5%

79.5%

90.5%

93.5%

(D=B*C)

Hedged Volume (TWh)

88.2

67.1

14.7

12.7

12.9

(E)

Effective Realized Energy Price ($/MWh)

$38.00

$48.00

$7.50

$7.00

$36.00

(F)

Reference Price ($/MWh)

$30.59

$38.24

$8.37

$4.42

$35.19

(G=E-F)

Difference ($/MWh)

$7.41

$9.76

($0.87)

$2.58

$0.81

(H=D*G)

Mark-to-market

value

of

hedges

($

million)

(1)

$655 million

$655 million

($15) million

$35 million

$10 million

(I=A+H)

Hedged Gross Margin ($ million)

$7,100 million

(J)

Power New Business / To Go ($ million)

$500 million

(K)

Non-Power Margins Executed ($ million)

$150 million

(L)

Non-

Power New Business / To Go ($ million)

$450 million

(N=I+J+K+L)

Total Gross Margin

$8,200 million

(1) Mark-to-market rounded to the nearest $5 million. 

2012 3Q Earnings Release Slides

2012 3Q Earnings Release Slides

ComEd Load Trends

-3%

-2%

-1%

0%

1%

2%

4Q12

3Q12

2Q12

1Q12

4Q11

3Q11

2Q11

1Q11

Gross Metro Product

Residential

Large C&I

All Customer Classes

2011 

3Q12        2012E

(3)

Average Customer Growth

0.4%  

0.3%    

0.3%

Average Use-Per-Customer

(1.7)%

1.1%

(0.9)%

Total Residential

(1.3)%   

1.4%         (0.6)%

Small C&I

(0.8)%

(0.1)%    

(0.2)%

Large C&I

0.6%  

(0.8)%     

(0.3)%

All Customer Classes

(0.5)%   

0.2%      

(0.3)%

Weather-Normalized Electric Load Year-over-Year

Key Economic Indicators

Weather-Normalized Electric Load

(1)

Source:  U.S. Dept. of Labor (September 2012) and Illinois

Department of Security (September 2012)

(2)

Source: Global Insight (August 2012)

(3)

Not adjusted for leap year

Chicago

U.S.

Unemployment rate

(1)

8.7%

7.8%               

2012 annualized growth in

gross domestic/metro product

(2)

1.7%                   2.1%

22

2012 3Q Earnings Release Slides

Notes: C&I = Commercial & Industrial. Global Insight re-stated 2011 GMP amounts in August 2012 so there will be a change since 2Q12 earnings release.

ComEd load activity impacts net income to the extent that it does not result in an ROE outside of the collar, which ensures that the earned ROE is within 0.5% of the allowed ROE.

23

PECO Load Trends

2011 

3Q12        2012E

(3)

Average Customer Growth

0.3%  

0.3%    

0.4%

Average Use-Per-Customer

1.3%

(3.9)%

(2.4)%

Total Residential

1.7%    

(3.6)%        (2.0)%

Small C&I

(0.7)%

(1.7)%    

(3.5)%

Large C&I

(3.3)%  

(4.8)%     

(2.4)%

All Customer Classes

(0.9)%   

(3.6)%     

(2.4)%

Weather-Normalized Electric Load Year-over-Year

Key Economic Indicators

Weather-Normalized Electric Load

(1)

Source:

U.S.

Dept.

of

Labor

(Sept

2012)

-

US

US

Dept

of

Labor

prelim.

data

(August

2012)

-

Philadelphia

(2)

Source: Global Insight (August 2012)

(3)

Not adjusted for leap year

Philadelphia

U.S.

Unemployment rate

(1)

8.8%

7.8%

2012 annualized growth in

gross domestic/metro product

(2)

1.9%                   2.1%

2012 3Q Earnings Release Slides

Note: C&I = Commercial & Industrial.  Global Insight re-stated 2011 GMP amounts in August 2012 so there will be a change since 2Q12 earnings release.

24

BGE Load Trends

-8%

-6%

-4%

-2%

0%

2%

4%

6%

4Q12

3Q12

2Q12

1Q12

4Q11

3Q11

2Q11

1Q11

Gross Metro Product

Residential

Large C&I

All Customer Classes

2011 

3Q12        2012E

(3)

Average Customer Growth

0.2%  

0.0%    

0.1%

Average Use-Per-Customer

(4.4)%

(1.4)%

(1.3)%

Total Residential

(4.3)%   

(1.4)%        (1.2)%

Small C&I

0.8%

0.5%    

(3.1)%

Large C&I

2.0%  

(0.3)%     

(0.6)%

All Customer Classes

(1.1)%   

(3.0)%     

(2.2)%

Weather-Normalized Electric Load Year-over-Year

Key Economic Indicators

Weather-Normalized Electric Load

(1)

Source:

U.S.

Dept.

of

Labor

(Sept

2012)

-

US

US

Dept

of

Labor

prelim.

data

(August

2012)

-

Baltimore

(2)

Source: Global Insight (August 2012)

(3)

Not adjusted for leap year

Baltimore

U.S.

Unemployment rate

(1)

7.7%

7.8%

2012 annualized growth in

gross domestic/metro product

(2)

1.7%                   2.1%

2012 3Q Earnings Release Slides

Note: C&I = Commercial & Industrial.  Global Insight re-stated 2011 GMP amounts in August 2012 so there will be a change since June 2012 Analyst Day presentation.

25

BGE Rate Case (Updated to reflect 10/22/12 filing)

Rate

Case

Request

(1)

Electric

Gas

Docket #

9299

Test Year

October 2011 –

September 2012

Common Equity Ratio

48.4%

Requested Returns

ROE: 10.5%; ROR: 7.96%

Rate Base

$2.7B

$1B

Revenue Requirement Increase

$131M

$45M

Proposed Distribution Price

Increase as % of overall bill

4%

6%

Timeline

•10/22/12: Update 8 months actual/4 month estimated test period data with actuals for last 4 months

(June-Sept. 2012)

•11/9/12: BGE and staff/intervenors file rebuttal testimony

•11/20/12: Staff/Intervenors  and BGE file surrebuttal testimony

•12/3/12 –

12/18/12: Hearings

•1/11/13: Initial Briefs

•1/23/13: Reply Briefs

•2/23/13: Decision

•New rates are in effect shortly after the decision

(1)

2012 3Q Earnings Release Slides

Initial filing on 7/27/12 used 8 months of actuals and 4 months of projections for October 2011 – September 2012 time period and requested an ROR of 8.02%, electric revenue

increase of $151M and gas revenue increase of $53M.  Rate base, equity ratio and ROE have not changed materially since the 7/27/12 filing.

Minimum Offer Price Rules (MOPR) Update

26

PJM is proposing modifications to the MOPR to ensure uneconomic generation does not

distort market

•

Restructured MOPR

MOPR to apply to all new gas-fired and IGCC units in PJM, with limited exceptions

MOPR exemption to be available only to self-supply entities and competitive market

entrants

MOPR

floor

to

apply

for

three

years,

set

at

100%

of

the

net

cost

of

new

entry

•

Implementation/Timing

PJM currently reviewing restructured MOPR with all stakeholders

PJM expected to file for FERC approval by November 30, 2012

Exelon, other generators, and other stakeholders to support PJM’s filing

FERC approval expected in early February, 2013

PJM RPM

Auction

2015/16 –

May 2012

Stakeholder

Discussions -

Summer 2012

FERC Filing –

November  30, 2012

PJM RPM

Auction

2016/17 –

Spring 2013

FERC Ruling –

February 1, 2013

2012 3Q Earnings Release Slides

Note: IGCC = Integrated Gasification Combined Cycle.  FERC = Federal Energy Regulatory Commission.  RPM= Reliability Pricing Model.

Sufficient Liquidity

(1)

Excludes commitments from Exelon’s Community and Minority Bank Credit Facility

(2)

Available Capacity Under Facilities represents the unused commitments under the borrower’s credit agreements net of outstanding letters of credit and facility draws. 

The amount of commercial paper outstanding does not reduce the available capacity under the credit agreements.

(3)

Includes Exelon Corporate’s $500M credit facility and legacy Constellation credit facilities assumed as part of the merger, letters of credit and commercial paper

outstanding.  Exelon will have unwound the $4.2B in credit facilities assumed from legacy Constellation by the end of the year.

($ in Millions)

Exelon Corp, ExGen, PECO and BGE facilities were amended and extended on August 10, 2012

to align maturities of facilities and secure liquidity and pricing through 2017

27

2012 3Q Earnings Release Slides

Aggregate Bank Commitments

(1)

600

1,000

600

5,600

9,800

Outstanding Facility Draws

--

--

--

--

--

Outstanding Letters of Credit

(1)

(121)

(1)

(1,950)

(2,089)

Available Capacity Under Facilities

(2)

599

879

599

3,650

7,711

Outstanding Commercial Paper

--

--

--

--

--

Available Capacity Less Outstanding

Commercial Paper

599

879

599

3,650

7,711

Available Capacity Under Bank Facilities as of October 24, 2012

(3)

28

ComEd Operating EPS Contribution

Key

Drivers

–

3Q12

vs.

3Q11

(1)

•

Share differential: $(0.04)

•

Decreased storm costs

(2)

: $0.04

•

Lower distribution revenue primarily due to

lower allowed ROE

(3)

: $(0.06)

(1)

(2)

(3)

3Q12

Actual

Actual

Normal

Heating Degree-Days        147           107          119

Cooling Degree-Days         785

859          613       

3Q11

2012 3Q Earnings Release Slides

$0.43

$0.17

$0.27

$0.10

YTD

3Q

2011

2012

Net of costs recoverable through EIMA. During the fourth quarter of 2011, ComEd received a credit of $0.04 earnings per share, net of amortization, for the allowed recovery of certain 2011

storm costs pursuant to EIMA. During the fourth quarter of 2012, ComEd anticipates recording $0.10 earnings per share to recognize the impact of the ICC’s rehearing decision issued on

October 3, 2012.

Due to the true-up mechanism in the distribution formula rate, the primary driver of year-over-year change in earnings will be due to changes in allowed ROE, rate base and capital structure.

Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

29

PECO Operating EPS Contribution

Key

Drivers

–

3Q12

vs.

3Q11

(1)

•

Lower income tax in 2011 due to electric

T&D tax repairs deduction: $(0.03)

•

Share differential: $(0.03)

•

Lower load growth: $(0.01)

•

Decreased storm costs: $0.02

•

Lower income tax in 2012 due to gas

distribution tax repairs deduction: $0.03

Note: T&D = Transmission and Distribution

3Q12

Actual

Actual

Normal

Heating Degree-Days        18              14              35

Cooling Degree-Days        1,109

1,138        934         

3Q11

$0.47

$0.16

$0.38

$0.14

YTD

3Q

2011

2012

2012 3Q Earnings Release Slides

(1)

Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS.

30

3Q GAAP EPS Reconciliation

Three Months Ended September 30, 2012

ExGen

ComEd

PECO

BGE

Other

Exelon

2012 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$0.53

$0.10

$0.14

$(0.00)

$(0.01)

$0.77

Mark-to-market impact of economic hedging activities

0.01

-

-

-

0.01

0.02

Unrealized gains related to nuclear decommissioning trust funds

0.04

-

-

-

-

0.04

Plant retirements and divestitures

(0.22)

-

-

-

-

(0.22)

Asset retirement obligation

(0.01)

-

-

-

-

(0.01)

Constellation merger and integration costs

(0.04)

-

(0.00)

(0.00)

(0.00)

(0.04)

Amortization of commodity contract intangibles

(0.21)

-

-

-

-

(0.21)

Amortization of the fair value of certain debt

0.00

-

-

-

-

0.00

3Q 2012 GAAP Earnings (Loss) Per Share

$0.11

$0.11

$0.14

$(0.00)

$(0.00)

$0.35

NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.

Three Months Ended September 30, 2011

ExGen

ComEd

PECO

Other

Exelon

2011 Adjusted (non-GAAP) Operating Earnings Per Share

$0.79

$0.17

$0.16

$0.01

$1.12

Mark-to-market impact of economic hedging activities

(0.08)

-

-

-

(0.08)

Unrealized losses related to nuclear decommissioning trust funds

(0.12)

-

-

-

(0.12)

Plant retirements and divestitures

(0.00)

-

-

-

(0.00)

Asset retirement obligation

(0.03)

-

0.00

-

(0.02)

Constellation merger and integration costs

(0.00)

(0.00)

(0.00)

(0.01)

(0.02)

Other acquisition costs

(0.01)

-

-

-

(0.01)

Wolf Hollow acquisition

0.03

-

-

-

0.03

3Q 2011 GAAP Earnings (Loss) Per Share

$0.58

$0.17

$0.16

$(0.00)

$0.90

2012 3Q Earnings Release Slides

31

YTD GAAP EPS Reconciliation

Nine Months Ended September 30, 2012

ExGen

ComEd

PECO

BGE

Other

Exelon

2012 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$1.57

$0.27

$0.38

$0.04

$(0.05)

$2.21

Mark-to-market impact of economic hedging activities

0.21

-

-

-

0.02

0.23

Unrealized gains related to nuclear decommissioning trust funds

0.07

-

-

-

-

0.07

Plant retirements and divestitures

(0.25)

-

-

-

-

(0.25)

Asset retirement obligation

(0.01)

-

-

-

-

(0.01)

Constellation merger and integration costs

(0.16)

-

(0.01)

(0.00)

(0.08)

(0.26)

Maryland commitments

(0.03)

-

-

(0.10)

(0.15)

(0.28)

Amortization of commodity contract intangibles

(0.68)

-

-

-

-

(0.68)

FERC settlement

(0.22)

-

-

-

-

(0.22)

Reassessment of state deferred income taxes

0.02

-

-

-

0.13

0.15

Amortization of the fair value of certain debt

0.01

-

-

-

-

0.01

Other acquisition costs

(0.00)

-

-

-

(0.00)

YTD 2012 GAAP Earnings (Loss) Per Share

$0.53

$0.27

$0.37

$(0.07)

$(0.13)

$0.97

Nine Months Ended September 30, 2011

ExGen

ComEd

PECO

Other

Exelon

2011 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share

$2.47

$0.43

$0.47

$(0.03)

$3.34

Mark-to-market impact of economic hedging activities

(0.34)

-

-

-

(0.34)

Unrealized losses related to nuclear decommissioning trust funds

(0.07)

-

-

-

(0.07)

Plant retirements and divestitures

(0.04)

-

-

-

(0.04)

Asset retirement obligation

(0.03)

-

0.00

-

(0.02)

Constellation merger and integration costs

(0.00)

(0.00)

(0.00)

(0.03)

(0.04)

Other acquisitions costs

(0.01)

-

-

-

(0.01)

Wolf Hollow acquisition

0.03

-

-

-

0.03

Recovery of costs pursuant to the 2011 distribution rate case order

-

0.03

-

-

0.03

Non-cash charge resulting from Illinois tax rate change legislation

(0.03)

(0.01)

-

(0.00)

(0.04)

YTD 2011 GAAP Earnings (Loss) Per Share

$1.99

$0.44

$0.47

$(0.07)

$2.84

2012 3Q Earnings Release Slides

NOTE:  All amounts shown are per Exelon share and represent contributions to Exelon's EPS.  Amounts may not add due to rounding.

GAAP to Operating Adjustments

32

•

Exelon’s 2012 adjusted (non-GAAP) operating earnings outlook excludes the earnings effects of the

following:

-

Mark-to-market adjustments from economic hedging activities

-

Unrealized gains and losses from nuclear decommissioning trust fund investments to the extent not

offset by contractual accounting as described in the notes to the consolidated financial statements

-

Financial impacts associated with the planned retirement of fossil generating units and the expected

sale in the fourth quarter of 2012 of three generating stations as required by the merger

-

Changes in decommissioning obligation estimates

-

Certain costs incurred related to the Constellation merger and integration initiatives

-

Costs incurred as part of Maryland commitments in connection with the merger

-

Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at

the merger date

-

Costs incurred as part of a March 2012 settlement with the Federal Energy Regulatory Commission

(FERC) related to Constellation’s prior period hedging and risk management transactions

-

Changes in state deferred tax rates resulting from a reassessment of anticipated apportionment of

Exelon’s deferred taxes as a result of the merger

-

Non-cash amortization of certain debt recorded at fair value at the merger date expected to be retired in

2013

-

Certain costs incurred associated with other acquisitions

-

Significant impairments of assets, including goodwill

-

Other unusual items

-

Significant changes to GAAP

•

Operating

earnings

guidance

assumes

normal

weather

for

remainder

of

the

year

2012 3Q Earnings Release Slides